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  • 10-K (Feb 18, 2015)
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  • 10-K (Feb 24, 2012)

 
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Helix Energy Solutions 10-K 2009
form10-k.htm


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K

(Mark One)
R
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
For the fiscal year ended December 31, 2008
   
or
   
£
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) of the Securities Exchange Act of 1934
 
 
For the transition period from                                                      to                 

Commission File Number 001-32936

 

HELIX ENERGY SOLUTIONS GROUP, INC.
(Exact name of registrant as specified in its charter)

Minnesota
95-3409686
(State or other jurisdiction
of incorporation or organization)
(I.R.S. Employer
Identification No.)
   
400 North Sam Houston Parkway East Suite 400
77060
Houston, Texas
(Address of principal executive offices)
(Zip Code)

(281) 618-0400
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class
Name of each exchange on which registered
Common Stock (no par value)
New York Stock Exchange

Securities registered Pursuant to Section 12(g) of the Act:
None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.   R Yes  £ No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  £ Yes  R No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  R Yes  £ No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  £

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer R
Accelerated filer £
Non-accelerated filer £
Smaller reporting company £
   
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  £ Yes  R No

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant based on the last reported sales price of the Registrant’s Common Stock on June 30, 2008 was approximately $3.6 billion.

The number of shares of the registrant’s Common Stock outstanding as of February 27, 2009 was 98,386,640.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive Proxy Statement for the Annual Meeting of Shareholders to be held on May 13, 2009, are incorporated by reference into Part III hereof.


 

 
 

HELIX ENERGY SOLUTIONS GROUP, INC. INDEX — FORM 10-K

   
Page
PART I
Item 1.
Business                                                                                                                               
4
Item 1A.
Risk Factors                                                                                                                               
19
Item 1B.
Unresolved Staff Comments                                                                                                                               
28
Item 2.
Properties                                                                                                                               
28
Item 3.
Legal Proceedings                                                                                                                               
39
Item 4.
Submission of Matters to a Vote of Security Holders                                                                                                                               
40
Unnumbered Item
Executive Officers of the Company                                                                                                                               
40
PART II
Item 5.
Market for the Registrant’s Common Equity, Related Shareholder Matters and Issuer
     Purchases of Equity Securities                                                                                                                               
42
Item 6.
Selected Financial Data                                                                                                                               
42
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operation
44
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk                                                                                                                               
72
Item 8.
Financial Statements and Supplementary Data                                                                                                                               
73
 
Management’s Report on Internal Control Over Financial Reporting                                                                                                                               
74
 
Report of Independent Registered Public Accounting Firm                                                                                                                               
75
 
Report of Independent Registered Public Accounting Firm on Internal Control Over
     Financial Reporting                                                                                                                               
76
 
Consolidated Balance Sheets as of December 31, 2008 and 2007                                                                                                                               
77
 
Consolidated Statements of Operations for the Years Ended December 31, 2008, 2007 and 2006
78
 
Consolidated Statements of Shareholders’ Equity for the Years Ended
     December 31, 2008, 2007 and 2006                                                                                                                               
79
 
Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006
80
 
Notes to the Consolidated Financial Statements                                                                                                                               
81
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
136
Item 9A.
Controls and Procedures                                                                                                                               
136
Item 9B.
Other Information                                                                                                                               
136
PART III
Item 10.
Directors, Executive Officers and Corporate Governance                                                                                                                               
137
Item 11.
Executive Compensation                                                                                                                               
137
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
137
Item 13.
Certain Relationships and Related Transactions                                                                                                                               
137
Item 14.
Principal Accounting Fees and Services                                                                                                                               
137
PART IV
Item 15.
Exhibits, Financial Statement Schedules                                                                                                                               
140
 
Signatures                                                                                                                               
142


 
 
 

Forward Looking Statements

This Annual Report on Form 10-K (“Annual Report”) contains various statements that contain forward-looking information regarding Helix Energy Solutions Group, Inc. and represent our expectations and beliefs concerning future events.   This forward looking information is intended to be covered by the safe harbor for “forward-looking statements” provided by the Private Securities Litigation Reform Act of 1995 as set forth in Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, included herein or incorporated herein by reference, that are predictive in nature, that depend upon or refer to future events or conditions, or that use terms and phrases such as “achieve,” “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “plan,” “project,” “propose,” “strategy,” “predict,” “envision,” “hope,” “intend,” “will,” “continue,” “may,” “potential,” “should,” “could” and similar terms and phrases are forward-looking statements. Included in forward-looking statements are, among other things:    

statements regarding our business strategy, including the potential sale of assets and/or other investments in our subsidiaries and facilities, or any other business plans, forecasts or objectives, any or all of which is subject to change;

 
• statements regarding our anticipated production volumes, results of exploration, exploitation, development, acquisition or  operations expenditures, and current or prospective reserve levels with respect to any property or well;

statements related to commodity prices for oil and gas or with respect to the supply of and demand for oil and gas;

statements relating to our proposed acquisition, exploration, development and/or production of oil and gas properties, prospects or other interests and any anticipated costs related thereto;

statements related to environmental risks, exploration and development risks, or drilling and operating risks;

statements relating to the construction or acquisition of vessels or equipment and any anticipated costs related thereto;

statements that our proposed vessels, when completed, will have certain characteristics or the effectiveness of such characteristics;

statements regarding projections of revenues, gross margin, expenses, earnings or losses, working capital or other financial items;

statements regarding any financing transactions or arrangements, or ability to enter into such transactions;

statements regarding any Securities and Exchange Commission (“SEC”) or other governmental or regulatory inquiry or investigation;

statements regarding anticipated legislative, governmental, regulatory, administrative or other public body actions, requirements, permits or decisions;

statements regarding anticipated developments, industry trends, performance or industry ranking;

statements regarding general economic or political conditions, whether international, national or in the regional and local market areas in which we do business; 

statements related to our ability to retain key members of our senior management and key employees;

statements related to the underlying assumptions related to any projection or forward-looking statement; and

any other statements that relate to non-historical or future information.

Although we believe that the expectations reflected in these forward-looking statements are reasonable and are based on reasonable assumptions, they do involve risks, uncertainties and other factors that could cause actual results to be materially different from those in the forward-looking statements.  These factors include, among other things:

 
 
impact of the weak economic conditions and the future impact of such conditions on the oil and gas industry and the demand for our services;
 
 
uncertainties inherent in the development and production of oil and gas and in estimating reserves;


 
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the geographic concentration of our oil and gas operations;
 
 
uncertainties regarding our ability to replace depletion;
 
 
unexpected future capital expenditures (including the amount and nature thereof);
  
 
impact of oil and gas price fluctuations and the cyclical nature of the oil and gas industry;
  
 
the effects of indebtedness, which could adversely restrict our ability to operate, could make us vulnerable to general adverse economic and industry conditions, could place us at a competitive disadvantage compared to our competitors that have less debt and could have other adverse consequences to us;
  
 
the effectiveness of our derivative activities;
  
 
the results of our continuing efforts to control or reduce costs, and improve performance;
  
 
the success of our risk management activities;
  
 
the effects of competition;
  
 
the availability (or lack thereof) of capital (including any financing) to fund our business strategy and/or operations and the terms of any such financing;
  
 
the impact of current and future laws and governmental regulations including tax and accounting developments;
  
 
the effect of adverse weather conditions or other risks associated with marine operations;
  
 
the effect of environmental liabilities that are not covered by an effective indemnity or insurance;
  
 
the potential impact of a loss of one or more key employees; and
  
 
the impact of general, market, industry or business conditions.

Our actual results could differ materially from those anticipated in any forward-looking statements as a result of a variety of factors, including those discussed in “Risk Factors” beginning on page 19 of this Annual Report. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. Forward-looking statements are only as of the date they are made, and other than as required under the securities laws, we assume no obligation to update or revise these forward-looking statements or provide reasons why actual results may differ.

PART I

Item 1.  Business

OVERVIEW

Helix Energy Solutions Group, Inc. (“Helix”) is an international offshore energy company, incorporated in the state of Minnesota in 1979, that provides reservoir development solutions and other contracting services to the energy market as well as to our own oil and gas properties. Our Contracting Services segment utilizes our vessels, offshore equipment and proprietary technologies to deliver services that may reduce finding and development (“F&D”) costs and encompass the complete lifecycle of an offshore oil and gas field. Our Oil and Gas segment engages in prospect generation, exploration, development and production activities. Our primary operations are located in the Gulf of Mexico, North Sea, Asia Pacific and Middle East regions. Unless the context indicates otherwise, as used in this Annual Report, the terms “Company,” “we,” “us” and “our” refer collectively to Helix and its subsidiaries, including Cal Dive International, Inc. (collectively with its subsidiaries referred to as “Cal Dive” or “CDI”), a publicly traded majority-owned subsidiary.

In December 2008, we announced the intention to focus and shape the future of the Company around our deepwater construction and well intervention services.   For additional information regarding this recent strategy announcement and about our deepwater construction and well intervention services see sections titled “Industry and Our Strategy,”  “Contracting Services” and “Contracting Services Operations” all included elsewhere within Item 1. “Business” of this Annual Report.

Our principal executive offices are located at 400 North Sam Houston Parkway East, Suite 400, Houston, Texas 77060; phone number 281-618-0400. Our common stock trades on the New York Stock Exchange (“NYSE”) under the ticker symbol “HLX” and Cal Dive’s common stock also trades on the NYSE under the ticker symbol “DVR”.  Our Chief Executive Officer submitted the annual CEO certification to the NYSE as required under the its listed Company Manual in April 2008. Our principal executive officer and our principal financial officer have made the certifications required under Section 302 of the Sarbanes-Oxley Act, which are included as exhibits to this report.

Please refer to the subsection “— Certain Definitions” on page 8 for definitions of additional terms commonly used in this Annual Report.

 
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CONTRACTING SERVICES

We seek to provide services and methodologies which we believe are critical to finding and developing offshore reservoirs and maximizing production economics, particularly from marginal fields. By “marginal,” we mean reservoirs that are no longer wanted by major operators or are considered too small to be material to them. Our “life of field” services are organized in five disciplines: construction, well operations, reservoir and well technology services, drilling, and production facilities. We have disaggregated our contracting services operations into three reportable segments in accordance with Financial Accounting Standards Board (“FASB”) Statement No. 131 Disclosures about Segments of an Enterprise and Related Information (“SFAS No. 131”): Contracting Services (which includes subsea construction, well operations, reservoir and well technology services and drilling); Shelf Contracting; and Production Facilities.

Construction

For over 30 years, we have supported offshore oil and natural gas infrastructure projects by providing our services, which include the construction and maintenance of pipelines, production platforms, risers and subsea production systems primarily in the Gulf of Mexico, North Sea, Asia Pacific and Middle East regions. Our subsea construction services include pipelay and robotics in water depths exceeding 1,000 feet. We also provide construction services periodically from our well intervention vessels. We perform traditional subsea services, including air and saturation diving, salvage work and shallow water pipelay on the Outer Continental Shelf (“OCS”) of the Gulf of Mexico in water depths up to 1,000 feet through Cal Dive, a majority-owned subsidiary in which we currently own approximately 51%. The financial results of Cal Dive are consolidated in our accompanying financial statements as of December 31, 2008 and 2007 and for each of the years in the three-year period ending December 31, 2008 (see Item 8. Financial Statements and Supplementary Data”).

Well Operations

We engineer, manage and conduct well construction, intervention and decommissioning operations in water depths ranging from 200 to 10,000 feet. Over the long term, we expect an increased demand for these services caused by the growing number of subsea tree installations, coupled with our lower cost solutions as compared to a deepwater rig. Accordingly, we are constructing a newbuild vessel (the “Well Enhancer”) and have expanded geographically in Australia and Asia in 2007 with the acquisition of Seatrac Pty Ltd. (“Seatrac”), an established Australian well operations company now called Well Ops SEA Pty Limited (“WOSEA”).

Reservoir and Well Technology Services

Our ownership of Helix RDS Limited (“Helix RDS”) makes us one of the largest outsource providers of sub-surface technology skills in the North Sea. With a staff base of over 120 employees, we have the resources to provide valuable well enhancement services, which typically increase production or extend the life of a reservoir, to our own oil and natural gas projects as well as to our clients. Each team we assign to a specific client comprises a diverse set of skills, including reservoir engineering, geology, modeling, flow assurance, completions, well design and production enhancement. Helix RDS has an established market presence in regions that we have identified as strategically important to future growth, including offices in Aberdeen and London in the United Kingdom, Kuala Lumpur, Malaysia and Perth, Australia.

Drilling

Contract drilling is a service we have not historically provided but have been contemplating since the construction of our Q4000 vessel over eight years ago. We added drilling capability to the Q4000 in 2008.  The fundamentals for deepwater rigs have been favorable in recent years, reflecting significant demand and a limited availability of such rigs.  Although the deterioration in the worldwide capital markets has led a number of oil and gas companies to recently curtail or to announce anticipated reductions in their near-term capital expenditure budgets, we believe that the long-term deepwater projects will be less affected because of the significant oil and gas reserves associated with such projects and the relatively long lead times required to develop these fields for production.  The drilling and completion cost of a subsea development can be as much as 50% of the total F&D costs for a deepwater prospect. The Q4000’s drilling capability primarily focuses on the use of hybrid slim-bore technology capable of drilling and completing 6-inch slimbore wells to 22,000 feet total depth and operating in up to 6,000 feet of water, which will allow us to drill many of our own deepwater prospects and support the exploration and appraisal efforts of our clients. We expect approval from the MMS in 2009 for cased well services, including completions, and approval for drilling once we have satisfied MMS requirements.

 
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Production Facilities

We own interests in certain production facilities in hub locations where there is potential for significant subsea tieback activity. Ownership of production facilities enables us to earn a transmission company type return through tariff charges while providing construction work for our vessels. We own a 50% interest in the Marco Polo tension leg platform (“TLP”), which was installed in 4,300 feet of water in the Gulf of Mexico, through Deepwater Gateway, L.L.C. (“Deepwater Gateway”). We also own a 20% interest in Independence Hub, L.L.C. (“Independence Hub”), an affiliate of Enterprise Products Partners L.P. Independence Hub owns a 105-foot deep draft, semi-submersible platform, which was installed during 2007. The Independence Hub platform is located in a water depth of 8,000 feet and serves as a regional hub for up to 1 billion cubic feet of natural gas production per day from multiple ultra-deepwater fields in the eastern Gulf of Mexico. Finally, through a consolidated 50% owned entity, we are actively converting a vessel into a floating production unit, which we intend to initially use to handle the future oil and gas production from our Phoenix field in the Gulf of Mexico (see Item 2. Properties – Significant Oil and Gas Properties).


OIL AND GAS

We formed our oil and gas operations in 1992 to develop and provide more efficient solutions for the abandonment requirements of companies operating offshore, to expand the asset utilization of our contracting services assets and to achieve incremental returns for our contracting services. We have evolved this business model to include not only mature oil and gas properties but also proved and unproved reserves yet to be developed and explored. In July 2006, we acquired Remington Oil and Gas Corporation (“Remington”), an exploration, development and production company with operations located primarily in the Gulf of Mexico. This acquisition has led to the assembly of services that allows us to create value at key points in the life of a reservoir from exploration through development and operating through the field’s final abandonment.  As of December 31, 2008, we had 665 Bcfe of estimated proved reserves with approximately 98% associated with properties located in the Gulf of Mexico. As discussed in “The Industry and Our Strategy” below, in December 2008, we announced that we intend to seek the potential sale of part or all of our oil and gas operations, however; until any potential disposition occurs, we believe that owning interests in reservoirs, particularly in deepwater, provides the following:

a potential backlog for our service assets as a hedge against cyclical service asset utilization;

potential utilization for new non-conventional applications of service assets to hedge against lack of initial market acceptance and utilization risk; and

incremental returns.

Our oil and gas operations include an experienced team of personnel providing services in geology, geophysics, reservoir engineering, drilling, production engineering, facilities management, lease operations and petroleum land management. We seek to maximize returns on our oil and gas investments by lowering F&D costs, reducing development time, operating our fields more effectively, and extending the reservoir life through well exploitation operations. Our reservoir engineering and geophysical expertise, along with our access to contracting services assets that may positively impact a project’s development costs, have enabled us to partner with many other oil and gas companies in offshore development projects.

Our contracting services includes three of our business segments, Contracting Services, Shelf Contracting and Production Facilities.   Our fourth business segment is Oil and Gas.  Significant financial information relating to our operations by segments and by geographic areas for the last three years is contained in Item 8. Financial Statements and Supplementary Data “— Note 19 — Business Segment Information.”

THE INDUSTRY AND OUR STRATEGY

In December 2008, we announced our intention to focus and shape the future direction of the Company around our deepwater construction and well intervention services. We intend to achieve this strategic focus by seeking and evaluating strategic opportunities to:

 
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1)  
Divest all or a portion of our oil and gas assets;
2)  
Divest our ownership interests in one or all production facilities; and
3)  
Dispose of our remaining 51% interest in our majority owned subsidiary, CDI.

We have engaged financial advisors to assist us in these efforts.   The current economic and financial market conditions may affect the timing of any strategic dispositions by us and will require a degree of patience in order to execute any transactions.   As a result, we are unable to be specific with respect to a timetable for any disposition, but we intend to aggressively focus on reducing our indebtedness through monetization of non-core assets and allocation of free cash flow in order to accelerate our strategic goals.   We cannot assure you that any or all of the proposed strategic dispositions will be completed or that we will be able to negotiate a favorable price and/or terms.  Dispositions of any  material assets and/or investments in our non-core businesses will require obtaining approval from our Board of Directors before consummation.

Consistent with this strategy, in December 2008 we announced the sale of our 17.5% non-operating working interest in the Bass Lite oil and gas field for $49 million in gross proceeds and in January 2009 we entered into a stock repurchase agreement with CDI that resulted in us selling approximately 13.6 million shares of CDI common stock held by us to CDI for $86 million in gross proceeds.   The sale reduced our ownership of CDI from approximately 57% to our current approximate 51% ownership position.

Demand for our contracting services operations is primarily influenced by the condition of the oil and gas industry, and in particular, the willingness of oil and gas companies to make capital expenditures for offshore exploration, drilling and production operations. Generally, spending for our contracting services fluctuates directly with the direction of oil and natural gas prices. The performance of our oil and gas operations is also largely dependent on the prevailing market prices for oil and natural gas, which are impacted by global economic conditions, hydrocarbon production and excess capacity, geopolitical issues, weather and several other factors.

The global economic conditions deteriorated significantly over the past year with declines in the oil and gas market accelerating during the fourth quarter of 2008.  Although we currently are experiencing a current market downturn, we believe that the long-term industry fundamentals are positive based on the following factors: (1) long term  increasing world demand for oil and natural gas; (2) peaking global production rates; (3) globalization of the natural gas market; (4) increasing number of mature and small reservoirs; (5) increasing ratio of contribution to global production from marginal fields; (6) increasing offshore activity, particularly in Deepwater; and (7) increasing number of subsea developments. Our current strategy of combining contracting services operations and oil and gas operations allows us to focus on trends (4) through (7) in that we pursue long-term sustainable growth by applying specialized subsea services to the broad external offshore market but with a complementary focus on marginal fields and new reservoirs in which we have an equity stake.

Our primary goal is to provide services and methodologies to the industry which we believe are critical to finding and developing offshore reservoirs and maximizing the economics from marginal fields. A secondary goal is for our oil and gas operations to generate prospects and find and develop oil and gas employing our key services and methodologies resulting in a reduction in F&D costs. Meeting these objectives drives our ability to achieve our primary goal of maximizing the value for our shareholders. In order to achieve these goals we will:

Continue Expansion of Contracting Services Capabilities.  We will focus on providing offshore services that deliver the highest financial return to us. We may make strategic investments in capital projects that expand our service capabilities or add capacity to existing services in our key operating regions. Our capital investments have included adding offshore drilling capability to our Q4000 vessel, converting a vessel into a dynamically positioned floating production unit (Helix Producer I), converting a former dynamically positioned cable lay vessel into a deepwater pipelay vessel (the Caesar), and constructing the Well Enhancer vessel with greater well servicing capabilities in the North Sea.

Monetize Oil and Gas Reserves and Non-Core Assets.  We intend to sell down interests in oil and gas reserves once value has been created via prospect generation, discovery and/or development engineering. Through this approach we seek to lower reservoir and commodity risk, lower capital expenditures and increase third party contracting services profits.  We may sell interests in oil and gas reserves at any time during the life of the properties.

As stated previously, we will focus on services which are critical to lowering F&D costs, particularly on marginal fields in the deepwater. As the strategy of our Shelf Contracting segment does not focus on minimizing F&D cost, in December 2006, a minority stake (26.5%) in this business was sold through a carve-out initial public offering. Our interest in CDI was further reduced

 
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through CDI’s acquisition of Horizon Offshore, Inc. (“Horizon”) in December 2007 and was 57.2% at December 31, 2008.  In January 2009, CDI acquired 13.6 million shares of its outstanding common shares from us reducing our current ownership in CDI to approximately 51%.  See Item 8. Financial Statements and Supplementary Data “— Note 5 — Acquisition of Horizon Offshore, Inc.” We believe the Shelf Contracting segment, CDI, is better positioned for growth as a stand-alone entity.

Generate Prospects and Focus Exploration Drilling on Select Deepwater Prospects.  Our oil and gas operations continue to function normally following our December 2008 announcement that all or a portion of such properties may be sold.  This means  we will continue to generate prospects and drill in areas where we believe our contracting services assets can be utilized and incremental returns will be achieved through control of and application of our development services and methodologies. To minimize our F&D costs, we expect to utilize the Q4000 for many of our deepwater drilling needs once regulatory approval has been obtained. Additionally, we plan to seek partners on these prospects to mitigate risk associated with the cost of drilling and development work.

Continue Exploitation Activities and Converting PUD/PDNP Reserves into Production.  Over the years, our oil and gas operations have been able to achieve a significant return on capital due in part to our ability to convert proved undeveloped reserves (“PUD”) and proved developed non-producing reserves (“PDNP”) into producing assets through successful exploitation drilling and well work. As of December 31, 2008, the PUD category  for our U.S Gulf of Mexico properties, totaled  approximately 319 Bcfe or 49% of our total domestic estimated proved reserves.   All of our U.K proved reserves are considered to be PUD at December 31, 2008.  We will focus on cost effectively developing these reserves to generate oil and gas production, or alternatively, selling full or partial interests in them to fund our core service business and/or retire outstanding debt.


Certain Definitions

Defined below are certain terms helpful to understanding our business:

Bcfe:  One billion cubic feet equivalent, with one barrel of oil being equivalent to six thousand cubic feet of natural gas.

Deepwater:  Water depths exceeding 1,000 feet.

Dive Support Vessel (DSV):  Specially equipped vessel that performs services and acts as an operational base for divers, remotely operated vehicles (“ROV”) and specialized equipment.

Dynamic Positioning (DP):  Computer-directed thruster systems that use satellite-based positioning and other positioning technologies to ensure the proper counteraction to wind, current and wave forces enabling the vessel to maintain its position without the use of anchors.

DP-2:  Two DP systems on a single vessel pursuant to which the redundancy allows the vessel to maintain position even with the failure of one DP system, required for vessels which support both manned diving and robotics and for those working in close proximity to platforms. DP-2 are necessary to provide the redundancy required to support safe deployment of divers, while only a single DP system is necessary to support ROV operations.

EHS:  Environment, Health and Safety programs to protect the environment, safeguard employee health and eliminate injuries.

E&P:  Oil and gas exploration and production activities.

F&D:  Total cost of finding and developing oil and gas reserves.

G&G:  Geological and geophysical.

IMR:  Inspection, maintenance and repair activities.

Life of Field Services:  Services performed on offshore facilities, trees and pipelines from the beginning to the end of the economic life of an oil field, including installation, inspection, maintenance, repair, contract operations, well intervention, recompletion and abandonment.

 
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MBbl:  When describing oil or other natural gas liquid, refers to 1,000 barrels containing 42 gallons each.

Minerals Management Service (MMS):  The federal regulatory body for the United States having responsibility for the mineral resources of the United States OCS.

Mcf:  When describing natural gas, refers to 1 thousand cubic feet.

MMcf:  When describing natural gas, refers to 1 million cubic feet.

Moonpool:  An opening in the center of a vessel through which a saturation diving system or ROV may be deployed, allowing safe deployment in adverse weather conditions.

MSV:  Multipurpose support vessel.

Outer Continental Shelf (OCS):  For purposes of our industry, areas in the Gulf of Mexico from the shore to 1,000 feet of water depth.

Peer Group-Contracting Services:  Defined in this Annual Report as comprising FMC Technologies, Inc. (NYSE: FTI), Global Industries, Ltd. (NASDAQ: GLBL), McDermott International, Inc. (NYSE: MDR), Oceaneering International, Inc. (NYSE: OII), Cameron International Corporation (NYSE: CAM), Pride International, Inc. (NYSE: PDE), Oil States International, Inc. (NYSE: OIS), Rowan Companies, Inc. (NYSE: RDC), and Tidewater Inc. (NYSE: TDW).

Peer Group-Oil and Gas:  Defined in this Annual Report as comprising ATP Oil & Gas Corp (NASDAQ: ATPG), W&T Offshore, Inc. (NYSE: WTI), and Mariner Energy, Inc. (NYSE: ME).

Proved Developed Non-Producing (PDNP):   Proved developed oil and gas reserves that are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, or (2) wells that require additional completion work or future recompletion prior to the start of production.

Proved Developed Shut-In (PDSI):  Proved developed oil and gas reserves associated with wells that exhibited calendar year production, but were not online January 1, 2009.    

Proved Developed Reserves:  Reserves that geological and engineering data indicate with reasonable certainty to be recoverable today, or in the near future, with current technology and under current economic conditions.

Proved Undeveloped Reserves (PUD):  Proved undeveloped oil and gas reserves that are expected to be recovered from a new well on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Remotely Operated Vehicle (ROV):  Robotic vehicles used to complement, support and increase the efficiency of diving and subsea operations and for tasks beyond the capability of manned diving operations.

ROVDrill:  ROV deployed coring system developed to take advantage of existing ROV technology. The coring package, deployed with the ROV system, is capable of taking cores from the seafloor in water depths up to 3000m. Because the system operates from the seafloor there is no need for surface drilling strings and the larger support spreads required for conventional coring.

Saturation Diving:  Saturation diving, required for work in water depths between 200 and 1,000 feet, involves divers working from special chambers for extended periods at a pressure equivalent to the pressure at the work site.

Spar:  Floating production facility anchored to the sea bed with catenary mooring lines.

Spot Market:  Prevalent market for subsea contracting in the Gulf of Mexico, characterized by projects that are generally short in duration and often on a turnkey basis. These projects often require constant rescheduling and the availability or interchangeability of multiple vessels.

Stranded Field:  Smaller PUD reservoir that standing alone may not justify the economics of a host production facility and/or infrastructure connections.

 
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Subsea Construction Vessels:  Subsea services are typically performed with the use of specialized construction vessels which provide an above-water platform that functions as an operational base for divers and ROVs. Distinguishing characteristics of subsea construction vessels include DP systems, saturation diving capabilities, deck space, deck load, craneage and moonpool launching. Deck space, deck load and craneage are important features of a vessel’s ability to transport and fabricate hardware, supplies and equipment necessary to complete subsea projects.

Tension Leg Platform (TLP):  A floating production facility anchored to the seabed with tendons.

Trencher or Trencher System:  A subsea robotics system capable of providing post lay trenching, inspection and burial (PLIB) and maintenance of submarine cables and flowlines in water depths of 30 to 7,200 feet across a range of seabed and environmental conditions.

Ultra-Deepwater:  Water depths beyond 4,000 feet.

Working Interest:  The interest in an oil and natural gas property (normally a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and to a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith.

CONTRACTING SERVICES OPERATIONS

We provide a full range of contracting services primarily in the Gulf of Mexico, North Sea, Asia Pacific and Middle East regions in both the shallow water and deepwater. Our services include:

Exploration support.  Pre-installation surveys; rig positioning and installation assistance; drilling inspection; subsea equipment maintenance; reservoir engineering; G&G services; modeling; well design; and engineering;

Development.  Installation of small platforms on the OCS, installation of subsea pipelines, flowlines, control umbilicals, manifolds, risers; pipelay and burial; installation and tie-in of riser and manifold assembly; commissioning, testing and inspection; and cable and umbilical lay and connection;

Production.  Inspection, maintenance and repair of production structures, risers, pipelines and subsea equipment; well intervention; life of field support; reservoir management; provision of production technology; and intervention engineering; and

Decommissioning.  Decommissioning and remediation services; plugging and abandonment services; platform salvage and removal services; pipeline abandonment services; and site inspections.

We provide offshore services and methodologies that we believe are critical to finding and developing offshore reservoirs and maximizing production economics, particularly from marginal fields. These “life of field” services are represented by five disciplines: (1) construction, (2) well operations, (3) reservoir and well technology services, (4) drilling and (5) production facilities. As of December 31, 2008, our contracting services operations’ backlog supported by written agreements or contracts totaled  $897.8 million, of which $668.4 million was expected to be completed in 2009.  These backlog contracts are cancellable without penalty in many cases.  Backlog is not a reliable indicator of total annual revenue for our Contracting Services businesses as contracts may be added, cancelled and in many cases modified while in progress.

Construction

Subsea

Construction services which we believe are critical to the development of fields in the deepwater include the use of  pipelay vessels and remotely operated vessels (“ROVs”).  We currently own three subsea umbilical and pipelay vessels. The Intrepid is a 381-foot DP-2 vessel capable of laying rigid and flexible pipe (up to 8 inches in diameter) and umbilicals. The Express is a 502-foot DP-2 vessel also capable of laying rigid and flexible pipe (up to 14 inches in diameter) and umbilicals. In January 2006, we acquired the Caesar, a mono-hull built in 2002 for the cable lay market. The Caeser is 485 feet long and has a state-of-the-art DP-2 system. We are currently converting the Caeser into a subsea pipelay asset capable of laying rigid pipe up to 42 inches in diameter.  Our total investment in the Caesar is expected to range between $210 million and $230 million when it is completed, which is expected in the

 
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 second half of 2009.  We also periodically provide construction services from our well intervention vessels, Seawell and Q4000. A new well intervention vessel, the Well Enhancer, is expected to be placed in service in the second quarter of 2009.

We operate ROVs, trenchers and ROV Drills designed for offshore construction, rather than supporting drilling rig operations. As marine construction support in the Gulf of Mexico and other areas of the world moves to deeper waters, use of ROV systems is increasing and the scope of their services is more significant. Our vessels add value by supporting deployment of our ROVs. We provide our customers with vessel availability and schedule flexibility to meet the technological challenges of these subsea construction developments in the Gulf of Mexico and internationally. Our 38 ROVs and six trencher systems operate in three regions: the Americas, Europe/West Africa and Asia Pacific.

The results of our Subsea division are reported under our Contracting Services segment. See Item 8. Financial Statements and Supplementary Data “— Note 19 — Business Segment Information.”

Shelf Contracting

Our Shelf Contracting segment represents the operations and results of CDI, our consolidated, majority-owned subsidiary. CDI provides manned diving services, pipelay and pipebury services with CDI’s six pipelay/pipebury barges.  These barges are able to install, bury and repair pipelines having outside diameters of up to 36 inches, and employ conventional S-lay technology that is appropriate for operating on the Gulf of Mexico OCS and the international areas where we currently operate.  CDI also performs platform installation and salvage services utilizing CDI’s two derrick barges which are equipped with cranes designed to lift and place platforms, structures or equipment into position for installation.  Based on the size of its fleet, we believe that CDI is the market leader in the diving support business, which involves services such as construction, inspection, maintenance, repair and decommissioning of offshore production and pipeline infrastructure on the Gulf of Mexico OCS. CDI also provides these services directly or through partnering relationships in select international offshore markets, such as the Middle East and Asia Pacific. Within this segment we currently own and operate a diversified fleet of 31 vessels, including 21 surface and saturation diving support vessels, six pipelay/pipebury barges, one dedicated pipebury barge, one combination derrick/pipelay barge and two derrick barges. Pipelay and pipe burial operations typically require extensive use of our diving services; therefore, we consider these services to be complementary.

Shelf Contracting performs saturation, surface and mixed gas diving which enable us to provide a full complement of manned diving services in water depths of up to 1,000 feet. CDI provides saturation diving services in water depths of 200 to 1,000 feet through its fleet of eight saturation diving vessels and ten portable saturation diving systems. We also believe that CDI’s fleet of diving support vessels is among the most technically advanced in the industry because a number of these vessels have features such as dynamic positioning, hyperbaric rescue chambers, multi-chamber systems for split-level operations and moon pool deployment, which allow us to operate effectively in challenging offshore environments. CDI provides surface and mixed gas diving services in water depths typically less than 300 feet through our 13 surface diving vessels.  We believe that CDI’s fleet of diving support vessels is the largest in the world.

On December 11, 2007, CDI completed its acquisition of Horizon, through the merger of Horizon with and into a wholly owned subsidiary of CDI, which resulted in Horizon becoming a wholly owned subsidiary of CDI. Under the terms of the merger, each share of Horizon’s common stock was converted into the right to receive $9.25 in cash and 0.625 shares of CDI’s common stock. All shares of Horizon restricted stock that had been issued but had not vested prior to the effective time of the merger became fully vested at the effective time of the merger and converted into the right to receive the merger consideration. CDI issued an aggregate of approximately 20.3 million shares of common stock and paid approximately $300 million in cash in the merger. The cash portion of the merger consideration was paid from CDI’s cash on hand and from borrowings under its $675 million credit facility consisting of a $375 million senior secured term loan and a $300 million senior secured revolving credit facility. See Item 8. Financial Statements and Supplementary Data “— Note 11 — Long-Term Debt.”

     In January 2009, CDI purchased from us approximately 13.6 million shares of its common stock for  $86 million or $6.34 per share. We still hold approximately 47.9 million shares of CDI common stock representing approximately 51% of its total outstanding shares of common stock.

CDI has substantially increased the size of its Shelf Contracting fleet and expanded its operating capabilities on the Gulf of Mexico OCS through strategic acquisitions of Horizon (2007), Acergy US, Inc. (“Acergy”) (2006), and the assets of Torch (2005). CDI also acquired Fraser Diving International Limited (“Fraser”) (2006).

 
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Shelf Contracting retained our former name of “Cal Dive,” and completed a carve-out initial public offering in December 2006. It trades on the New York Stock Exchange under the ticker symbol of “DVR.” We received pre-tax net proceeds of $464.4 million from the initial public offering (“IPO”), which included the sale of a 26.5% interest and transfer of debt to CDI.

The results of shelf contracting services are reported under our Shelf Contracting Services segment. See Item 8. Financial Statements and Supplementary Data “— Note 19 — Business Segment Information.”

Well Operations

We engineer, manage and conduct well construction, intervention, and decommissioning operations in water depths ranging from 200 to 10,000 feet. The increased number of subsea wells installed and the shortfall in both rig availability and equipment have resulted in an increased demand for Well Operations services in both the Gulf of Mexico and the North Sea.

As major and independent oil and gas companies expand operations in the deepwater basins of the world, development of these reserves will often require the installation of subsea trees. Historically, drilling rigs were typically necessary for subsea well operations to troubleshoot or enhance production, shift zones or perform recompletions. Two of our vessels serve as work platforms for well operations services at costs significantly less than drilling rigs. In the Gulf of Mexico, our multi-service semi-submersible vessel, the Q4000, has set a series of well operations “firsts” in increasingly deeper water without the use of a traditional drilling rig. In the North Sea, the Seawell has provided intervention and abandonment services for over 500 North Sea subsea wells since 1987. Competitive advantages of our vessels are derived from their lower operating costs, together with an ability to mobilize quickly and to maximize production time by performing a broad range of tasks related to intervention, construction, inspection, repair and maintenance. These services provide a cost advantage in the development and management of subsea reservoir developments. With the expected long-term increased demand for these services due to the growing number of subsea tree installations, we have significant backlog for both working assets and, as a result, are constructing a newbuild North Sea vessel, the Well Enhancer. The total cost of the Well Enhancer is expected to be between $200 million and $220 million when it is completed, which is anticipated in the second quarter of 2009.  Our operations expanded within Australia and Asia following the acquisition of a well-established Australian well operations company in 2006.

The results of Well Operations are reported under our Contracting Services segment. See Item 8. Financial Statements and Supplementary Data “— Note 19 — Business Segment Information.”


Reservoir and Well Technology Services

In 2005, we acquired Helix Energy Limited, which wholly owns Helix RDS, an outsource provider of sub-surface technology skills in the North Sea. With a staff base of over 120 employees, we have the resources to provide valuable well enhancement services, which typically increase production or extend the life of a reservoir, to our own oil and natural gas projects as well as provide these services to our clients. Each team we assign to a specific client comprises a diverse set of skills, including reservoir engineering, geology, modeling, flow assurance, completions, well design and production enhancement. Helix RDS has an established market presence in regions identified as strategically important to our future growth, including offices in Aberdeen and London in the United Kingdom, Kuala Lumpur, Malaysia and Perth, Australia.

The results of reservoir and well technology services are reported under our Contracting Services segment. See Item 8. Financial Statements and Supplementary Data “— Note 19 — Business Segment Information.”

Drilling

Contract drilling is a service we have not historically provided but have been contemplating since the construction of our Q4000 vessel over eight years ago. We added drilling capability to the Q4000 in 2008.  The fundamentals for deepwater rigs have been favorable in recent years, reflecting significant demand and a limited availability of such rigs.   Although the deterioration in the worldwide capital markets led  a number of oil and gas companies to recently curtail or announce anticipated reductions to their near-term capital expenditure budgets, we believe that the long-term deepwater projects will mostly be unaffected because of the significant oil and gas reserves associated with such projects and the relatively long lead times required to develop these fields for production, The drilling cost of a subsea development can be as much as 50% of the total F&D costs for a deepwater prospect. The Q4000’s drilling capability primarily focuses on the use hybrid slim-bore technology capable of drilling and completing 6-inch slimbore wells to 22,000 feet total depth and operating in up to 6,000 feet of water, which will allow us to drill many of our own deepwater prospects

 
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and support the exploration and appraisal efforts of our clients. We expect approval from the MMS for cased well services including completions in 2009 and approval for drilling once we have satisfied MMS requirements.

The results of drilling services are reported under our Contracting Services segment. See Item 8. Financial Statements and Supplementary Data “— Note 19 — Business Segment Information.”


Production Facilities

We own interests in certain production facilities in hub locations where there is potential for significant subsea tieback activity. There are a significant number of small discoveries that cannot justify the economics of a dedicated host facility. These discoveries are typically developed as subsea tie backs to existing facilities when capacity through the facility is available. We have historically invested in over-sized facilities that allow operators of these fields to tie back without burdening the operator of the hub reservoir. We are positioned to facilitate the tie back of certain of these smaller reservoirs to these hubs through our services. Ownership of production facilities enables us to earn a transmission company type return through tariff charges while providing construction work for our vessels. We own a 50% interest in Deepwater Gateway which owns the Marco Polo TLP, which was installed in 4,300 feet of water in the Gulf of Mexico in order to process production from the Marco Polo field discovery. We also own a 20% interest in Independence Hub which owns the Independence Hub platform, a 105-foot deep draft, semi-submersible platform located in a water depth of 8,000 feet that serves as a regional hub for up to 1 billion cubic feet of natural gas production per day from multiple ultra-deepwater fields in the previously untapped eastern Gulf of Mexico.

When a hub is not feasible, we intend to apply an integrated application of our services in a manner that cumulatively lowers development costs to a point that allows for a small dedicated facility to be used. This strategy will permit the development of some fields that otherwise would be non-commercial to develop. The commercial risk is mitigated because we have a portfolio of reservoirs and the assets to redeploy the facility. For example, through a consolidated 50% owned entity, we are currently converting a vessel into a dynamically positioned floating production unit. We intend this unit to first be utilized on the Phoenix field, which we acquired in 2006 after the hurricanes of 2005 destroyed the TLP which was being used to produce the field. Once production in the Phoenix area ceases, this re-deployable facility is expected to be moved to a new location, contracted to a third party, or used to produce other internally-owned reservoirs.

The results of production facilities services are reported under our Production Services segment. See Item 8. Financial Statements and Supplementary Data “— Note 19 — Business Segment Information.”

OIL & GAS OPERATIONS

We formed our oil and gas operations in 1992 to develop and provide more efficient solutions for offshore abandonment requirements, to expand the utilization of our contracting services assets and to achieve incremental returns for our contracting services. We have evolved this business model to include not only mature oil and gas properties but also proved and unproved reserves yet to be developed and explored. In July 2006, we acquired Remington, an exploration, development and production company with operations primarily in the Gulf of Mexico, for approximately $1.4 billion in cash and Helix common stock and the assumption of $358.4 million of liabilities. This acquisition led to the assembly of services that allows us to create value at key points in the life of a reservoir from exploration through development, life of field management and operating through abandonment. As of December 31, 2008, our estimated proved reserves totaled 665 Bcfe with approximately 98% of such reserves associated with properties located in the Gulf of Mexico.

     As announced in December 2008, we seek to monetize the value of our oil and gas assets through the disposition of all or a portion of our oil and gas operations.  Although this is our intention, until such time as an acceptable offer is made for our properties we will continue to build on their value by operating them consistent with our past practices.   We cannot assure you that the sale of all or any portion of the oil and gas operations will be completed or that we will be able to negotiate an acceptable price or acceptable terms.  Also, any material disposition of assets and/or investments in our non-core businesses will require obtaining approval from our Board of Director’s before any definitive agreement can be reached. We believe that owning interests in reservoirs, particularly in deepwater, provides the following:

a potential backlog for our service assets as a hedge against cyclical service asset utilization;

 
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potential utilization for new non-conventional applications of service assets to hedge against lack of initial market acceptance and utilization risk; and

incremental returns.

Our oil and gas operations are currently involved in all stages of a reservoir’s life. This complete life-cycle involvement allows us to meaningfully improve the economics of a reservoir that would otherwise be considered non-commercial or non-impact and has identified us as a value adding partner to many producers. Our expertise, along with similarly aligned interests, allows us to develop more efficient relationships with other producers. With a historical focus on acquiring non-impact reservoirs or mature fields, we have been successful in acquiring equity interests in several deepwater undeveloped reservoirs. In the event we continue to own and operate our oil and gas assets, developing these fields over the next few years will require significant capital commitments by us or others and may provide significant backlog for our construction assets.

Our oil and gas operations have a significant prospect inventory, mostly in the deepwater, which we believe will generate significant life of field services for our vessels. To minimize F&D costs, we expect to utilize the Q4000 for many of our deepwater future drilling needs. Our Oil and Gas segment has a proven track record of cost effectively turning prospects into production on the OCS, and we believe similar success is achievable in the deepwater. We plan to seek partners on these prospects to mitigate risk associated with the cost of  drilling and development work.

We identify prospective oil and gas properties primarily by using 3-D seismic technology. After acquiring an interest in a prospective property, our strategy is to partner with others to drill one or more exploratory wells. If the exploratory well(s) find commercial oil and/or gas reserves, we complete the well(s) and install the necessary infrastructure to begin producing the oil and/or gas. Because our operations are located offshore Gulf of Mexico, we must install facilities such as offshore platforms and gathering pipelines in order to produce the oil and gas and deliver it to the marketplace. Certain properties require additional drilling to fully develop the oil and gas reserves and maximize the production from a particular discovery.

Our oil and gas operations include an experienced team of personnel providing services in geology, geophysics, reservoir engineering, drilling, production engineering, facilities management, lease operations and petroleum land management. We seek to maximize profitability by lowering F&D costs, lowering development time and cost, operating the field more effectively, and extending the reservoir life through well exploitation operations. When a company sells an OCS property, it retains the financial responsibility for plugging and decommissioning if its purchaser becomes financially unable to do so. Thus, it becomes important that a property be sold to a purchaser that has the financial wherewithal to perform its contractual obligations. We believe we have a strong reputation among major and independent oil companies. In addition, our reservoir engineering and geophysical expertise, along with our access to contracting service assets that can positively impact development costs, have enabled us to partner with many other oil and gas companies in offshore development projects. We share ownership in our oil and gas properties with various industry participants. We currently operate the majority of our offshore properties. An operator is generally able to maintain a greater degree of control over the timing and amount of capital expenditures than a non-operating interest owner. See Item 2. Properties “— Summary of Natural Gas and Oil Reserve Data” for detailed disclosures of our oil and gas properties.

The results of our oil and gas operations are reported under our Oil and Gas segment. See Item 8. Financial Statements and Supplementary Data “— Note 19 — Business Segment Information.”

GEOGRAPHIC AREAS

Revenue by geographic region during is as follows (in thousands):

     
Year Ended December 31,
 
     
2008
     
2007
     
2006
 
United States
 
$
1,394,246
   
$
1,261,844
   
$
1,063,821
 
United Kingdom
   
181,108
     
230,189
     
190,064
 
India
   
214,288
     
36,433
     
 
Other
   
358,707
     
238,979
     
113,039
 
     Total
 
$
2,148,349
   
$
1,767,445
   
$
1,366,924
 
                         

We include the property and equipment, net in the geographic region in which it is legally owned.  The following table provides our property and equipment, net of depreciation by geographic region (in thousands):


     
Year Ended December 31,
 
     
2008
     
2007
     
2006
 
United States
 
$
3,170,866
   
$
3,014,283
   
$
2,068,342
 
United Kingdom
   
207,156
     
189,117
     
110,451
 
Other
   
41,568
     
41,288
     
33,665
 
     Total
 
$
3,419,590
   
$
3,244,688
   
$
2,212,458
 

CUSTOMERS

Our customers include major and independent oil and gas producers and suppliers, pipeline transmission companies and offshore engineering and construction firms. The level of construction services required by any particular contracting customer depends on the size of that customer’s capital expenditure budget devoted to construction plans in a particular year. Consequently, customers that account for a significant portion of contract revenues in one fiscal year may represent an immaterial portion of contract revenues in subsequent fiscal years. The percent of consolidated revenue of major customers, those whose total represented 10% or more of our consolidated revenues, was as follows: 2008 — Louis Dreyfus Energy Services (10%) and Shell Offshore, Inc. (11%); 2007 — Louis Dreyfus Energy Services (13%) and Shell Offshore, Inc. (10%); and 2006 — Louis Dreyfus Energy Services (10%) and Shell Trading (US) Company (10%). All of these customers were purchasers of our oil and gas production. We estimate that in 2008 we provided subsea services to over 200 customers.

Our contracting services projects have historically been of short duration and are generally awarded shortly before mobilization. As a result, no significant backlog existed prior to 2007. Beginning in 2007, we have entered into several long-term contracts, for certain of our Deepwater and Well Operations vessels. In addition, our production portfolio inherently provides a backlog of work for our services that we can complete at our option based on market conditions.

COMPETITION

The marine contracting industry is highly competitive. While price is a factor, the ability to acquire specialized vessels, attract and retain skilled personnel, and demonstrate a good safety record are also important. Our competitors on the OCS include Global Industries, Ltd., Oceaneering International, Inc. and a number of smaller companies, some of which only operate a single vessel and often compete solely on price. For Deepwater projects, our principal competitors include Acergy S.A., Allseas Group S.A., Subsea 7 Inc. and Technip-Coflexip.

Our oil and gas operations compete with large integrated oil and gas companies as well as independent exploration and production companies for offshore leases on properties. We also encounter significant competition for the acquisition of mature oil and gas properties. Our ability to acquire additional properties depends upon our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment. Many of our competitors may have significantly more financial, personnel, technological, and other resources available to them. In addition, some of the larger integrated companies may be better able to respond to industry changes including price fluctuation, oil and gas demands, and governmental regulations. Small or mid-sized producers, and in some cases financial players, with a focus on acquisition of proved developed and undeveloped reserves, are often competition on development properties.

TRAINING, SAFETY AND QUALITY ASSURANCE

We have established a corporate culture in which EHS remains among the highest of priorities. Our corporate goal, based on the belief that all accidents can be prevented, is to provide an injury-free workplace by focusing on correct and safe behavior. Our EHS procedures, training programs and management system were developed by management personnel, common industry work practices and by employees with on-site experience who understand the physical challenges of the ocean work site. As a result, management believes that our EHS programs are among the best in the industry. We have introduced a company-wide effort to enhance and provide continuous improvements to our behavioral based safety process, as well as our training programs, that continue to focus on safety through open communication. The process includes the documentation of all daily observations, collection of data and data

 
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treatment to provide the mechanism of understanding both safe and unsafe behaviors at the worksite. In addition, we initiated scheduled Hazard Hunts by project management on each vessel, complete with assigned responsibilities and action due dates. To further this effort, progressive auditing is done to continuously improve our EHS management system.


GOVERNMENT REGULATION

Many aspects of the offshore marine construction industry are subject to extensive governmental regulations. We are subject to the jurisdiction of the U.S. Coast Guard (“USCG”), the U.S. Environmental Protection Agency, the MMS and the U.S. Customs Service, as well as private industry organizations such as the American Bureau of Shipping (“ABS”). In the North Sea, international regulations govern working hours and a specified working environment, as well as standards for diving procedures, equipment and diver health. These North Sea standards are some of the most stringent worldwide. In the absence of any specific regulation, our North Sea operations adhere to standards set by the International Marine Contractors Association and the International Maritime Organization. In addition, we operate in other foreign jurisdictions that have various types of governmental laws and regulations to which we are subject.

We support and voluntarily comply with standards of the Association of Diving Contractors International. The Coast Guard sets safety standards and is authorized to investigate vessel and diving accidents, and to recommend improved safety standards. The Coast Guard also is authorized to inspect vessels at will. We are required by various governmental and quasi-governmental agencies to obtain various permits, licenses and certificates with respect to our operations. We believe that we have obtained or can obtain all permits, licenses and certificates necessary for the conduct of our business.

In addition, we depend on the demand for our services from the oil and gas industry, and therefore, our business is affected by laws and regulations, as well as changing tax laws and policies, relating to the oil and gas industry generally. In particular, the development and operation of oil and gas properties located on the OCS of the United States is regulated primarily by the MMS.

The MMS requires lessees of OCS properties to post bonds or provide other adequate financial assurance in connection with the plugging and abandonment of wells located offshore and the removal of all production facilities. Operators on the OCS are currently required to post an area-wide bond of $3.0 million, or $0.5 million  per producing lease. We have provided adequate financial assurance for our offshore leases as required by the MMS.

We acquire production rights to offshore mature oil and gas properties under federal oil and gas leases, which the MMS administers. These leases contain relatively standardized terms and require compliance with detailed MMS regulations and orders pursuant to the Outer Continental Shelf Lands Act (“OCSLA”). These MMS directives are subject to change. The MMS has promulgated regulations requiring offshore production facilities located on the OCS to meet stringent engineering and construction specifications. The MMS also has issued regulations restricting the flaring or venting of natural gas and prohibiting the burning of liquid hydrocarbons without prior authorization. Similarly, the MMS has promulgated other regulations governing the plugging and abandonment of wells located offshore and the removal of all production facilities. Finally, under certain circumstances, the MMS may require any operations on federal leases to be suspended or terminated or may expel unsafe operators from existing OCS platforms and bar them from obtaining future leases. Suspension or termination of our operations or expulsion from operating on our leases and obtaining future leases could have a material adverse effect on our financial condition and results of operations.

Under the OCSLA and the Federal Oil and Gas Royalty Management Act, MMS also administers oil and gas leases and establishes regulations that set the basis for royalties on oil and gas. The regulations address the proper way to value production for royalty purposes, including the deductibility of certain post-production costs from that value. Separate sets of regulations govern natural gas and oil and are subject to periodic revision by MMS.

Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (“NGPA”), and the regulations promulgated thereunder by the Federal Energy Regulatory Commission (“FERC”). In the past, the federal government has regulated the prices at which oil and gas could be sold. While sales by producers of natural gas, and all sales of crude oil, condensate and natural gas liquids currently can be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead sales in the natural gas industry began with the enactment of the NGPA. In 1989, the Natural Gas Wellhead Decontrol Act was enacted. This act amended the NGPA to remove both price and non-price controls from natural gas sold in “first sales” no later than January 1, 1993.

 
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Sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. Several major regulatory changes have been implemented by Congress and FERC since 1985 that affect the economics of natural gas production, transportation and sales. In addition, FERC continues to promulgate revisions to various aspects of the rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject to FERC jurisdiction. Changes in FERC rules and regulations may also affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. We cannot predict what further action FERC will take on these matters, but we do not believe any such action will materially adversely affect us differently from other companies with which we compete.

Additional proposals and proceedings before various federal and state regulatory agencies and the courts could affect the oil and gas industry. We cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. There is no assurance that the regulatory approach currently pursued by FERC will continue indefinitely. Notwithstanding the foregoing, we do not anticipate that compliance with existing federal, state and local laws, rules and regulations will have a material effect upon our capital expenditures, financial conditions, earnings or competitive position.

ENVIRONMENTAL REGULATION

Our operations are subject to a variety of national (including federal, state and local) and international laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often complex and costly to comply with and that carry substantial administrative, civil and possibly criminal penalties for failure to comply. Under these laws and regulations, we may be liable for remediation or removal costs, damages and other costs associated with releases of hazardous materials (including oil) into the environment, and such liability may be imposed on us even if the acts that resulted in the releases were in compliance with all applicable laws at the time such acts were performed. Some of the environmental laws and regulations that are applicable to our business operations are discussed in the following paragraphs, but the discussion does not cover all environmental laws and regulations that govern our operations.

The Oil Pollution Act of 1990, as amended (“OPA”), imposes a variety of requirements on “Responsible Parties” related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. A “Responsible Party” includes the owner or operator of an onshore facility, a vessel or a pipeline, and the lessee or permittee of the area in which an offshore facility is located. OPA imposes liability on each Responsible Party for oil spill removal costs and for other public and private damages from oil spills. Failure to comply with OPA may result in the assessment of civil and criminal penalties. OPA establishes liability limits of $350 million for onshore facilities, all removal costs plus $75 million for offshore facilities, and the greater of $0.8 million or $0.95 million  per gross ton for vessels other than tank vessels. The liability limits are not applicable, however, if the spill is caused by gross negligence or willful misconduct; if the spill results from violation of a federal safety, construction, or operating regulation; or if a party fails to report a spill or fails to cooperate fully in the cleanup. Few defenses exist to the liability imposed under OPA. Management is currently unaware of any oil spills for which we have been designated as a Responsible Party under OPA that will have a material adverse impact on us or our operations.

OPA also imposes ongoing requirements on a Responsible Party, including preparation of an oil spill contingency plan and maintaining proof of financial responsibility to cover a majority of the costs in a potential spill. We believe that we have appropriate spill contingency plans in place. With respect to financial responsibility, OPA requires the Responsible Party for certain offshore facilities to demonstrate financial responsibility of not less than $35 million, with the financial responsibility requirement potentially increasing up to $150 million if the risk posed by the quantity or quality of oil that is explored for or produced indicates that a greater amount is required. The MMS has promulgated regulations implementing these financial responsibility requirements for covered offshore facilities. Under the MMS regulations, the amount of financial responsibility required for an offshore facility is increased above the minimum amounts if the “worst case” oil spill volume calculated for the facility exceeds certain limits established in the regulations. We believe that we currently have established adequate proof of financial responsibility for our onshore and offshore facilities and that we satisfy the MMS requirements for financial responsibility under OPA and applicable regulations.

In addition, OPA requires owners and operators of vessels over 300 gross tons to provide the Coast Guard with evidence of financial responsibility to cover the cost of cleaning up oil spills from such vessels. We currently own and operate 25 vessels over 300 gross tons. We have provided satisfactory evidence of financial responsibility to the Coast Guard for all of our vessels.

The Clean Water Act imposes strict controls on the discharge of pollutants into the navigable waters of the United States and imposes potential liability for the costs of remediating releases of petroleum and other substances. The controls and restrictions

 
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imposed under the Clean Water Act have become more stringent over time, and it is possible that additional restrictions will be imposed in the future. Permits must be obtained to discharge pollutants into state and federal waters. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System Program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the exploration for, and production of, oil and gas into certain coastal and offshore waters. The Clean Water Act provides for civil, criminal and administrative penalties for any unauthorized discharge of oil and other hazardous substances and imposes liability on responsible parties for the costs of cleaning up any environmental contamination caused by the release of a hazardous substance and for natural resource damages resulting from the release. Many states have laws that are analogous to the Clean Water Act and also require remediation of releases of petroleum and other hazardous substances in state waters. Our vessels routinely transport diesel fuel to offshore rigs and platforms and also carry diesel fuel for their own use. Our vessels transport bulk chemical materials used in drilling activities and also transport liquid mud which contains oil and oil by-products. Offshore facilities and vessels operated by us have facility and vessel response plans to deal with potential spills. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.

OCSLA provides the federal government with broad discretion in regulating the production of offshore resources of oil and gas, including authority to impose safety and environmental protection requirements applicable to lessees and permittees operating in the OCS. Specific design and operational standards may apply to OCS vessels, rigs, platforms, vehicles and structures. Violations of lease conditions or regulations issued pursuant to OCSLA can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and cancellation of leases. Because our operations rely on offshore oil and gas exploration and production, if the government were to exercise its authority under OCSLA to restrict the availability of offshore oil and gas leases, such action could have a material adverse effect on our financial condition and results of operations. As of this date, we believe we are not the subject of any civil or criminal enforcement actions under OCSLA.

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) contains provisions requiring the remediation of releases of hazardous substances into the environment and imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons including owners and operators of contaminated sites where the release occurred and those companies who transport, dispose of, or arrange for disposal of hazardous substances released at the sites. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. Third parties may also file claims for personal injury and property damage allegedly caused by the release of hazardous substances. Although we handle hazardous substances in the ordinary course of business, we are not aware of any hazardous substance contamination for which we may be liable.

We operate in foreign jurisdictions that have various types of governmental laws and regulations relating to the discharge of oil or hazardous substances and the protection of the environment. Pursuant to these laws and regulations, we could be held liable for remediation of some types of pollution, including the release of oil, hazardous substances and debris from production, refining or industrial facilities, as well as other assets we own or operate or which are owned or operated by either our customers or our sub-contractors.

Management believes that we are in compliance in all material respects with all applicable environmental laws and regulations to which we are subject. We do not anticipate that compliance with existing environmental laws and regulations will have a material effect upon our capital expenditures, earnings or competitive position. However, changes in the environmental laws and regulations, or claims for damages to persons, property, natural resources or the environment, could result in substantial costs and liabilities, and thus there can be no assurance that we will not incur significant environmental compliance costs in the future.


EMPLOYEES

We rely on the high quality of our workforce. As of January 31, 2009, we had approximately 3,600 employees, nearly 800 of which were salaried personnel. Of the total employees, approximately 2,000 were employees of Cal Dive. As of December 31, 2008, we also contracted with third parties to utilize 636 non-U.S. citizens to crew our foreign flag vessels. None of our employees belong to a union nor are employed pursuant to any collective bargaining agreement or any similar arrangement. We believe our relationship with our employees and foreign crew members is favorable.

 
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WEBSITE AND OTHER AVAILABLE INFORMATION

We maintain a website on the Internet with the address of www.HelixESG.com. Copies of this Annual Report for the year ended December 31, 2008, and copies of our Quarterly Reports on Form 10-Q for 2008 and 2009 and any Current Reports on Form 8-K for 2008 and 2009, and any amendments thereto, are or will be available free of charge at such website as soon as reasonably practicable after they are filed with, or furnished to, the Securities and Exchange Commission (“SEC”). In addition, the Investor Relations portion of our website contains copies of our Code of Conduct and Business Ethics and our Code of Ethics for Chief Executive Officer and Senior Financial Officers. We make our website content available for informational purposes only. Information contained on our website is not part of this report and should not be relied upon for investment purposes. Please note that prior to March 6, 2006, the name of the Company was Cal Dive International, Inc.

The general public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. We are an electronic filer, and the SEC maintains an Internet website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including us. The Internet address of the SEC’s website is www.sec.gov.

Item 1A.  Risk Factors.

Shareholders should carefully consider the following risk factors in addition to the other information contained herein. You should be aware that the occurrence of the events described in these risk factors and elsewhere in this Annual Report could have a material adverse effect on our business, results of operations and financial position.

Risks Relating to General Corporate Matters

Economic conditions could negatively impact our business.

Our operations are affected by local, national and worldwide economic conditions and the condition of the oil and gas industry.  During recent months, there has been a substantial downturn in business activity and in the worldwide credit and capital markets that has led to a worldwide economic recession. The consequences of a prolonged recession will include a lower level of economic activity and increased uncertainty regarding the direction of energy prices and the capital and commodity markets, which will likely contribute to decreased offshore exploration and drilling. A lower level of offshore exploration and drilling could have a material adverse effect on the demand for our services.  In addition a general decline in the level of economic activity might result in lower commodity prices, which may also adversely affect our revenues from our oil and gas business and indirectly, our service business. 

Continued market deterioration could also jeopardize the performance of certain counterparty obligations, including those of our insurers, customers and financial institutions.   Although we monitor the creditworthiness of our counterparties, the current market conditions could lead to sudden changes in a counterparty’s liquidity.  In the event any such party fails to perform, our financial results could be adversely affected and we could incur losses and our liquidity could be negatively impacted.
 
  Because of significant declines in both our stock price and commodity prices, in the fourth quarter of 2008 we were required to reduce the amount of our recorded goodwill and other indefinite lived intangibles by approximately $715 million by taking an asset impairment charge to operating expense, most of which affected our oil and gas segment ($704 million). Further stock price or commodity price decreases may result in additional impairment expense charges for our long-lived assets and/or our goodwill associated with our contracting services operations and this could negatively impact our financial condition.  Impairment charges do not affect our current or future cash flow.
 

Lack of access to the credit market could negatively impact our ability to operate our business and to execute our business strategy.

Due to the substantial uncertainty in the global economy, there has been deterioration in the credit and capital markets and access to financing is limited and uncertain.  If the capital and credit markets continue to experience weakness and the availability of funds remains limited, we may incur increased costs associated with any additional financing we may require for future operations.  Because of uncertainty in the market and an inability to access the capital markets our customers may curtail their capital and operating expenditure programs, which could result in a decrease in demand for our vessels and a reduction in fees and/or utilization. In

 
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addition, certain of our customers could experience an inability to pay suppliers, including us, in the event they are unable to access the capital markets as needed to fund their business operations.  Likewise, our suppliers may be unable to sustain their current level of operations, fulfill their commitments and/or fund future operations and obligations, each of which could adversely affect our operations.
 
In addition, continued lower levels of economic activity and weakness in the credit markets could adversely affect our ability to implement our strategic objectives and dispose of all or any portion of the oil and gas assets, the production facilities or our interest in CDI.  We cannot assure you that the proposed strategic dispositions will be completed or that we will be able to negotiate prices or terms that are acceptable to us.
 

Our substantial indebtedness and the terms of our indebtedness could impair our financial condition and our ability tofulfill our debt obligations.>

As of December 31, 2008, we had approximately $2.1 billion of consolidated indebtedness outstanding ($315 million of which relates to CDI which is non recourse to us). The significant level of combined indebtedness may have an adverse effect on our future operations, including:

limiting our ability to obtain additional financing on satisfactory terms to fund our working capital requirements, capital expenditures, acquisitions, investments, debt service requirements and other general corporate requirements;

increasing our vulnerability to the continued general economic downturn, competition and industry conditions, which could place us at a competitive disadvantage compared to our competitors that are less leveraged;

increasing our exposure to rising interest rates because a portion of our current and potential future borrowings are at variable interest rates;

reducing the availability of our cash flow to fund our working capital requirements, capital expenditures, acquisitions, investments and other general corporate requirements because we will be required to use a substantial portion of our cash flow to service debt obligations;

limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and

limiting our ability to expand our business through capital expenditures or pursuit of acquisition opportunities due to negative covenants in senior secured credit facilities that place annual and aggregate limitations on the types and amounts of investments that we may make, and limit our ability to use proceeds from asset sales for purposes other than debt repayment (except in certain circumstances where proceeds may be reinvested under criteria defined by our credit agreements).

A continuing period of weak economic activity will make it increasingly difficult to comply with our covenants and other restrictions in agreements governing our debt.  Our ability to comply with these covenants and other restrictions is affected by the current economic conditions and other events beyond our control.  If we fail to comply with these covenants and other restrictions, it could lead to an event of default, the possible acceleration of our repayment of outstanding debt and the exercise of certain remedies by the lenders, including foreclosure on our pledged collateral.   We cannot assure you that we would have access to the credit markets as needed to replace our existing debt and we could incur increased costs associated with any available replacement financing.

Our operations outside of the United States subject us to additional risks.

Our operations outside of the United States are subject to risks inherent in foreign operations, including, without limitation:

the loss of revenue, property and equipment from expropriation, nationalization, war, insurrection, acts of terrorism and other political risks;

increases in taxes and governmental royalties;

changes in laws and regulations affecting our operations;

renegotiation or abrogation of contracts with governmental entities;

changes in laws and policies governing operations of foreign-based companies;

 
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currency restrictions and exchange rate fluctuations;

world economic cycles;

restrictions or quotas on production and commodity sales;

limited market access; and

other uncertainties arising out of foreign government sovereignty over our international operations.

In addition, laws and policies of the United States affecting foreign trade and taxation may also adversely affect our international operations.

Our ability to market oil and natural gas discovered or produced in any future foreign operations, and the price we could obtain for such production, depends on many factors beyond our control, including:

ready markets for oil and natural gas;

the proximity and capacity of pipelines and other transportation facilities;

fluctuating demand for crude oil and natural gas;

the availability and cost of competing fuels; and

the effects of foreign governmental regulation of oil and gas production and sales.

Pipeline and processing facilities do not exist in certain areas of exploration and, therefore, any actual sales of our production could be delayed for extended periods of time until such facilities are constructed.

We may not be able to compete successfully against current and future competitors.

The businesses in which we operate are highly competitive. Several of our competitors are substantially larger and have greater financial and other resources than we have. If other companies relocate or acquire vessels for operations in the Gulf of Mexico or the North Sea, levels of competition may increase and our business could be adversely affected. In the exploration and production business, some of the larger integrated companies may be better able to respond to industry changes including price fluctuations, oil and gas demands, political change and government regulations.

We may need to change the manner in which we conduct our business in response to changes in government regulations.>

Our subsea construction, intervention, inspection, maintenance and decommissioning operations and our oil and gas production from offshore properties, including decommissioning of such properties, are subject to and affected by various types of government regulation, including numerous federal, state and local environmental protection laws and regulations. These laws and regulations are becoming increasingly complex, stringent and expensive to comply with, and significant fines and penalties may be imposed for noncompliance. We cannot assure you that continued compliance with existing or future laws or regulations will not adversely affect our operations or financial condition or cash flow


Numerous federal and state regulations affect our operations. Current regulations are constantly reviewed by the various agencies at the same time that new regulations are being considered and implemented. In addition, because we hold federal leases, the federal government requires us to comply with numerous additional regulations that focus on government contractors. The regulatory burden upon the oil and gas industry increases the cost of doing business and consequently affects our profitability.

Our operations are subject to a variety of national (including federal, state and local) and international laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental

 
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agencies issue rules and regulations to implement and enforce such laws that are often complex and costly to comply with and that carry substantial administrative, civil and possibly criminal penalties for failure to comply. Under these laws and regulations, we may be liable for remediation or removal costs, damages and other costs associated with releases of hazardous materials including oil into the environment, and such liability may be imposed on us even if the acts that resulted in the releases were in compliance with all applicable laws at the time such acts were performed.

We operate in foreign jurisdictions that have various types of governmental laws and regulations relating to the discharge of oil or hazardous substances and the protection of the environment. Pursuant to these laws and regulations, we could be held liable for remediation of some types of pollution, including the release of oil, hazardous substances and debris from production, refining or industrial facilities, as well as other assets we own or operate or which are owned or operated by either our customers or our sub-contractors.

In addition, changes in environmental laws and regulations, or claims for damages to persons, property, natural resources or the environment, could result in substantial costs and liabilities, and thus there can be no assurance that we will not incur significant environmental compliance costs in the future. Such environmental liability could substantially reduce our net income and could have a significant impact on our financial ability to carry out our operations.


Our industry has lost a significant number of experienced professionals over the years due to, among other reasons, the volatility in commodity prices. Our continued success depends on the active participation of our key employees. The loss of our key people could adversely affect our operations.

In addition, the delivery of our products and services require personnel with specialized skills and experience. As a result, our ability to remain productive and profitable will depend upon our ability to employ and retain skilled workers. Our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. The demand for skilled workers in our industry is high, and the supply is limited. In addition, although our employees are not covered by a collective bargaining agreement, the marine services industry has in the past been targeted by maritime labor unions in an effort to organize Gulf of Mexico employees. A significant increase in the wages paid by competing employers or the unionization of our Gulf of Mexico employees could result in a reduction of our skilled labor force, increases in the wage rates that we must pay or both. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.


We have a history of growing through acquisitions of large assets and acquisitions of companies. We must plan and manage our acquisitions effectively to achieve revenue growth and maintain profitability in our evolving market. If we fail to effectively manage current and future acquisitions, our results of operations could be adversely affected. Our growth has placed significant demands on our personnel, management and other resources. We must continue to improve our operational, financial, management and legal/compliance information systems to keep pace with the growth of our business.


In addition to the 55,000 shares of preferred stock issued to Fletcher International, Ltd. under the First Amended and Restated Agreement dated January 17, 2003, but effective as of December 31, 2002, by and between Helix and Fletcher International, Ltd., our Articles of Incorporation give our board of directors the authority, without any action by our shareholders, to fix the rights and preferences on up to 4,945,000 shares of undesignated preferred stock, including dividend, liquidation and voting rights. In addition, our by-laws divide the board of directors into three classes. We are also subject to certain anti-takeover provisions of the Minnesota Business Corporation Act. We also have employment contracts with all of our executive officers that require cash payments in the event of a “change of control.” Any or all of the provisions or factors described above may discourage a takeover proposal or tender offer not approved by management and the board of directors and could result in shareholders who may wish to participate in such a proposal or tender offer receiving less for their shares than otherwise might be available in the event of a takeover attempt.

 
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Risks Relating to our Contracting Services Operations


Our contracting services operations are substantially dependent upon the condition of the oil and gas industry, and in particular, the willingness of oil and gas companies to make capital expenditures for offshore exploration, drilling and production operations. The level of capital expenditures generally depends on the prevailing view of future oil and gas prices, which are influenced by numerous factors affecting the supply and demand for oil and gas, including, but not limited to:



worldwide economic activity;

demand for oil and natural gas, especially in the United States, China and India;

economic and political conditions in the Middle East and other oil-producing regions;

actions taken by the Organization of Petroleum Exporting Countries (“OPEC”);

the availability and discovery rate of new oil and natural gas reserves in offshore areas;

the cost of offshore exploration for and production and transportation of oil and gas;

the ability of oil and natural gas companies to generate funds or otherwise obtain external capital for exploration, development and production operations;

the sale and expiration dates of offshore leases in the United States and overseas;

technological advances affecting energy exploration, production, transportation and consumption;

weather conditions;

environmental and other governmental regulations; and

tax laws, regulations and policies.

We cannot assure you that activity levels for offshore construction will remain the same or increase. A sustained period of low drilling and production activity or the return of lower commodity prices would likely have a material adverse effect on our financial position, cash flows and results of operations.


Marine construction involves a high degree of operational risk. Hazards, such as vessels sinking, grounding, colliding and sustaining damage from severe weather conditions, are inherent in marine operations. These hazards can cause personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, and suspension of operations. Damage arising from such occurrences may result in lawsuits asserting large claims. We maintain insurance protection as we deem prudent, including Jones Act employee coverage, which is the maritime equivalent of workers’ compensation, and hull insurance on our vessels. We cannot assure you that any such insurance will be sufficient or effective under all circumstances or against all hazards to which we may be subject. A successful claim for which we are not fully insured could have a material adverse effect on us. Moreover, we cannot assure you that we will be able to maintain adequate insurance in the future at rates that we consider reasonable. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, insurance carriers are now requiring broad exclusions for losses due to war risk and terrorist acts and limitations for wind storm damages. As construction activity expands into deeper water in the Gulf of Mexico and other deepwater basins of the world and with our partial divestiture of Cal Dive, a greater percentage of our revenues may be from deepwater construction projects that are larger and more complex, and thus riskier, than shallow water projects. As a result, our revenues and profits are increasingly dependent on our larger vessels. The current insurance on our vessels, in some cases, is in

 
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amounts approximating book value, which could be less than replacement value. In the event of property loss due to a catastrophic marine disaster, mechanical failure, collision or other event, insurance may not cover a substantial loss of revenues, increased costs and other liabilities, and therefore, the loss of any of our large vessels could have a material adverse effect on us.


Marine operations conducted in the Gulf of Mexico and North Sea are seasonal and depend, in part, on weather conditions. Historically, we have enjoyed our highest vessel utilization rates during the summer and fall when weather conditions are favorable for offshore exploration, development and construction activities. We typically have experienced our lowest utilization rates in the first quarter. As is common in the industry, we typically bear the risk of delays caused by some adverse weather conditions. Accordingly, our results in any one quarter are not necessarily indicative of annual results or continuing trends.

Certain areas in and near the Gulf of Mexico and North Sea experience unfavorable weather conditions including hurricanes and other extreme weather conditions on a relatively frequent basis. Substantially all of our facilities and assets offshore and along the Gulf of Mexico and the North Sea, including our vessels and structures on our offshore oil and gas properties, are susceptible to damage and/or total loss by these storms. Damage caused by high winds and turbulent seas could potentially cause us to curtail both service and production operations for significant periods of time until damage can be assessed and repaired. Moreover, even if we do not experience direct damage from any of these storms, we may experience disruptions in our operations because customers may curtail their development activities due to damage to their platforms, pipelines and other related facilities.

If we bid too low on a turnkey contract, we suffer adverse economic consequences.

A significant amount of our projects are performed on a qualified turnkey basis where described work is delivered for a fixed price and extra work, which is subject to customer approval, is billed separately. The revenue, cost and gross profit realized on a turnkey contract can vary from the estimated amount because of changes in offshore job conditions, variations in labor and equipment productivity from the original estimates, the performance of third parties such as equipment suppliers, or other factors. These variations and risks inherent in the marine construction industry may result in our experiencing reduced profitability or losses on projects.


We currently have the following significant construction projects in our contracting services operations:

the construction of the Well Enhancer, a North Sea well services vessel;

the conversion of the Caesar into a deepwater pipelay asset; and

the construction of the Helix Producer I, a minimal floating production unit to be initially utilized on the Phoenix field, through a consolidated 50% owned variable interest entity.

Although the construction contracts provide for delay penalties, these projects have been and continue to be subject to the risk of delay or cost overruns inherent in construction projects. These risks include, but are not limited to:

unforeseen quality or engineering problems;

work stoppages or labor shortage;

weather interference;

unanticipated cost increases;

delays in receipt of necessary equipment; and

inability to obtain the requisite permits or approvals.

 
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Significant delays could also have a material adverse effect on expected contract commitments for these assets and our future revenues and cash flow. We will not receive any material increase in revenue or cash flows from these assets until they are placed in service and customers enter into binding arrangements for the assets, which can potentially be several months after the construction or conversion projects are completed. Furthermore, we cannot assure you that customer demand for these assets will be as high as currently anticipated, and as a result, our future cash flows may be adversely affected. In addition, new assets from third-parties may also enter the market in the future and compete with us.

Risks Relating to our Oil and Gas Operations

Exploration and production of oil and natural gas is a high-risk activity and is subject to a variety of factors that we cannot control.>

Our oil and gas business is subject to all of the risks and uncertainties normally associated with the exploration for and development and production of oil and natural gas, including uncertainties as to the presence, size and recoverability of hydrocarbons. We may not encounter commercially productive oil and natural gas reservoirs. We may not recover all or any portion of our investment in new wells. The presence of unanticipated pressures or irregularities in formations, miscalculations or accidents may cause our drilling activities to be unsuccessful and/or result in a total loss of our investment, which could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, we often are uncertain as to the future cost or timing of drilling, completing and operating wells.

Projecting future natural gas and oil production is imprecise. Producing oil and gas reservoirs eventually have declining production rates. Projections of production rates rely on certain assumptions regarding historical production patterns in the area or formation tests for a particular producing horizon. Actual production rates could differ materially from such projections. Production rates also can depend on a number of additional factors, including commodity prices, market demand and the political, economic and regulatory climate.

Our business is subject to all of the operating risks associated with drilling for and producing oil and natural gas, including:

fires;

title problems;

explosions;

pressures and irregularities in formations;

equipment availability;

blow-outs and surface cratering;

uncontrollable flows of underground natural gas, oil and formation water;

natural events and natural disasters, such as loop currents, hurricanes and other adverse weather conditions;

pipe or cement failures;

casing collapses;

lost or damaged oilfield drilling and service tools;

abnormally pressured formations; and

environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.

If any of these events occurs, we could incur substantial losses as a result of injury or loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension of our operations and repairs to resume operations.

 
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Natural gas and oil prices are volatile, which makes future revenue uncertain.

Our financial condition, cash flow and results of operations depend in part on the prices we receive for the oil and gas we produce. The market prices for oil and gas are subject to fluctuation in response to events beyond our control, such as:

supply of and demand for oil and gas;

market uncertainty;

worldwide political and economic instability; and

government regulations.

Oil and gas prices have historically been volatile, and such volatility is likely to continue. Our ability to estimate the value of producing properties for acquisition or disposition, and to budget and project the financial returns of exploration and development projects is made more difficult by this volatility. In addition, to the extent we do not forward sell or enter into costless collars or swap contracts in order to hedge our exposure to price volatility, a dramatic decline in such prices could have a substantial and material effect on:

our revenues;

results of operations;

cashflow;

financial condition;

our ability to increase production and grow reserves in an economically efficient manner; and

our access to capital.

We have hedged approximately 73% of our anticipated production for 2009 with a combination of forward sale and financial hedge contracts.  The prices for these contracts are significantly higher than the prices for both crude oil and natural gas as of December 31, 2008 and as of the time of this filing on March 2, 2009.   If the prices for crude oil and natural gas do not increase from current levels, and we have not entered into additional forward sale or financial hedge contracts to stabilize our cash flows, our oil and gas revenues may decrease in 2010 and beyond, perhaps significantly, absent offsetting increases in production amounts.


Our concentration of oil and gas properties in the Gulf of Mexico makes us more vulnerable to the risks associated with operating in that area than our competitors with more geographically diverse operations. These risks include:

 
tropical storms and hurricanes, which are common in the Gulf of Mexico during certain times of the year;

 
extensive governmental regulation (including regulations that may, in certain circumstances, impose strict liability for pollution damage); and

 
interruption or termination of operations by governmental authorities based on environmental, safety or other considerations.

Any event affecting this area in which we operate our oil and gas operations may have an adverse effect on our results of operations and cash flow.  We also may incur substantial liabilities to third parties or governmental entities, which could have a material adverse effect on our results of operations and financial condition.

 
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Oil and gas prices can fluctuate significantly and have a direct impact on our revenues. To manage our exposure to the risks inherent in such a volatile market, from time to time we have forward sold for future physical delivery a portion of our future production. This means that a portion of our production is sold at a fixed price as a shield against dramatic price declines that could occur in the market. In addition, we have entered into costless collar contracts and swap contracts related to some of our future oil and gas production. We may from time to time engage in other hedging activities that limit our upside potential from price increases. These sales activities may limit our benefit from dramatic price increases.


This Annual Report contains estimates of our proved oil and gas reserves and the estimated future net cash flows therefrom based upon reports for the years ended December 31, 2008 and 2007, audited by our independent petroleum engineers. These reports rely upon various assumptions, including assumptions required by the SEC, as to oil and gas prices, drilling and operating expenses, capital expenditures, abandonment costs, taxes and availability of funds. The process of estimating oil and gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. As a result, these estimates are inherently imprecise. Actual future production, cash flows, development and production expenditures, operating and abandonment expenses and quantities of recoverable oil and gas reserves may vary from those estimated in these reports. Any significant variance in these assumptions could materially affect the estimated quantity and value of our proved reserves. You should not assume that the present value of future net cash flows from our proved reserves referred to in this Annual Report is the current market value of our estimated oil and gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the net present value estimate. In addition, if costs of abandonment are materially greater than our estimates, they could have an adverse effect on financial position, cash flows and results of operations.


As of December 31, 2008, approximately 11% of our total estimated proved reserves were PDNP, 27% were PDSI and approximately 49% were PUD. These reserves may not ultimately be developed or produced. Furthermore, not all of our PUD or PDNP may be ultimately produced during the time periods we have planned, at the costs we have budgeted, or at all, which in turn may have a material adverse effect on our results of operations.

Additionally approximately 98% of our estimated proved reserves are located in the Gulf of Mexico and we have one field, Bushwood located at Garden Banks Blocks 462, 463, 506 and 507, that represents approximately half of our total estimated proved reserves and related estimated discounted future net revenues as of December 31, 2008.  If the proved reserves at Bushwood are affected by any combination of adverse factors; our future estimates of proved reserves could be decreased, perhaps significantly, which may have an adverse effect on our future results of operations and cash flows.   Separately, without Bushwood’s future reserve potential, the value that we may be able to realize in any potential disposition of our oil and gas business would likely be significantly diminished.

Reserve replacement may not offset depletion.

Oil and gas properties are depleting assets. We replace reserves through acquisitions, exploration and exploitation of current properties. Approximately 87% of our proved reserves at December 31, 2008 are PUDs, PDSI and PDNP. Further, our proved producing reserves at December 31, 2008 are expected to experience annual decline rates ranging from 30% to 40% over the next ten years. If we are unable to acquire additional properties or if we are unable to find additional reserves through exploration or exploitation of our properties, our future cash flows from oil and gas operations could decrease.

 
26

 


We are in part dependent on third parties with respect to the transportation of our oil and gas production and in certain cases, third party operators who influence our productivity.

Notwithstanding our ability to produce hydrocarbons, we are dependent on third party transporters to bring our oil and gas production to the market. In the event a third party transporter experiences operational difficulties, due to force majeure, pipeline shut-ins, or otherwise, this can directly influence our ability to sell commodities that we are able to produce. In addition, with respect to oil and gas projects that we do not operate, we have limited influence over operations, including limited control over the maintenance of safety and environmental standards. The operators of those properties may, depending on the terms of the applicable joint operating agreement:

refuse to initiate exploration or development projects;

initiate exploration or development projects on a slower or faster schedule than we would prefer;

delay the pace of exploratory drilling or development; and/or

drill more wells or build more facilities on a project than we can afford, whether on a cash basis or through financing, which may limit our participation in those projects or limit the percentage of our revenues from those projects.

The occurrence of any of the foregoing events could have a material adverse effect on our anticipated exploration and development activities.

Our oil and gas operations involve significant risks, and we do not have insurance coverage for all risks.>

Our oil and gas operations are subject to risks incident to the operation of oil and gas wells, including, but not limited to, uncontrollable flows of oil, gas, brine or well fluids into the environment, blowouts, cratering, mechanical difficulties, fires, explosions or other physical damage, pollution and other risks, any of which could result in substantial losses to us. We maintain insurance against some, but not all, of the risks described above. As a result, any damage not covered by our insurance could have a material adverse effect on our financial condition, results of operations and cash flows.

Item 1B.  Unresolved Staff Comments.

None.

Item 2.  Properties.

We own a fleet of 39 vessels and 37 ROVs, 5 trenchers, and 2 ROVDrills. We also lease six vessels, one trencher and one ROV. We believe that the market in the Gulf of Mexico requires specially designed and/or equipped vessels to competitively deliver subsea construction and well operations services. Eleven of our vessels have DP capabilities specifically designed to respond to the deepwater market requirements. Fifteen of our vessels (13 of which are based in the Gulf of Mexico) have the capability to provide saturation diving services.

Divestitures in 2008

In March and April 2008, we sold a total 30% working interest in the Bushwood discoveries (Garden Banks Blocks 463, 506 and 507) and other Outer Continental Shelf oil and gas properties (East Cameron Blocks 371 and 381), in two separate transactions to affiliates of a private independent oil and gas company for total cash consideration of approximately $183.4 million (which included the purchasers’ share of incurred capital expenditures on these fields), and additional potential cash payments of up to $20 million based upon certain field production milestones.  The new co-owners will also pay their pro rata share of all future capital expenditures related to the exploration and development of these fields.  Decommissioning liabilities will be shared on a pro rata share basis between the new co-owners and us.  Proceeds from the sale of these properties were used to partially repay our outstanding revolving loans in April 2008.  As a result of these sales, we recognized a pre-tax gain of $91.6 million in the first half of 2008.

In May 2008, we sold all our interests in our onshore proved and unproved oil and gas properties located in the states of Texas, Mississippi, Louisiana, New Mexico and Wyoming (“Onshore Properties”) to an unrelated investor.  We sold these Onshore Properties for cash proceeds of $47.3 million and recorded a related loss of $11.9 million in the second quarter of 2008.  Proceeds

 
27

 

from the sale of these properties were used to reduce our outstanding revolving loans in May 2008.  Included in the cost basis of the Onshore Properties was $8.1 million of allocated goodwill from our Oil and Gas segment.

In December 2008, we announced the sale of all our interests in the Bass Lite field (Atwater Block 426), a 17.5% working interest, to our joint interest owners in the field for approximately $49 million.  The sale had three separate closings and an effective date of November 1, 2008.  Proceeds from the sale were used to fund our working capital requirements.

 
28

 

OUR VESSELS

Listing of Vessels, Barges and ROVs Related to Contracting Services Operations(1)

 
 
 
Flag
State             
 
Placed
in
Service(2)
 
 
Length
(Feet)
 
 
 
Berths
 
 
SAT
      Diving         
 
DP or
Anchor
Moored          
 
Crane
   Capacity
   (tons)                
CONTRACTING SERVICES:
             
Pipelay —
             
Caesar (3)(4)
Vanuatu
1/2006
482
220
DP
300 and 36
Express (4)
Vanuatu
8/2005
520
132
DP
500 and 120
Intrepid (4)
Bahamas
8/1997
381
50
DP
400
Talisman (4)
U.S.
11/2000
195
14
REM Forza (10)
Norway
  9/2008
   355
   120
Capable
DP
250
Floating Production Unit —
             
Helix Producer I (5)
Bahamas
528
95
DP
26 and 26
Well Operations —
             
Q4000 (6)
U.S.
4/2002
312
135
DP
160 and 360; 600 Derrick
Seawell
U.K.
7/2002
368
129
Capable
DP
130
Well Enchancer (7)
U.K.
432
120
Capable
DP
100
Robotics —
             
38 ROVs,  6 Trenchers and 2 ROVDrills (8)(9)
Various
Northern Canyon (10)
Bahamas
6/2002
276
58
DP
50
Olympic Canyon (10)
Norway
4/2006
304
87
DP
150
Olympic Triton (10)
Norway
11/2007
311
87
DP
150
Seacor Canyon (10)
Majuro Marshall Island
4/2007
221
40
DP
20
Island Pioneer (10)
Vanuatu
5/2008
312
110
DP
140
SHELF CONTRACTING (CAL DIVE INTERNATIONAL, INC.):
             
Pipelay/Pipebury —
             
Brave (11)
U.S.
11/2005
275
80
Anchor
30 and 50
Rider (11)
U.S.
11/2005
260
80
Anchor
50
American (11)
U.S.
12/2007
180
74
Anchor
90
Lone Star (11)
Vanuatu
12/2007
313
177
Anchor
88
Brazos (11)
Vanuatu
12/2007
210
119
Anchor
90
Pecos (11)
U.S.
12/2007
256
102
Anchor
114
Pipebury —
             
Canyon (11)
Vanuatu
12/2007
330
110
Anchor
88
Derrick/Pipelay —
             
Sea Horizon
Vanuatu
12/2007
360
255
Anchor
1,200
Derrick —
             
Atlantic (11)
U.S.
12/2007
420
158
Anchor
500
Pacific (11)
U.S.
12/2007
350
109
Anchor
1,000
Saturation Diving —
             
DP DSV Eclipse (11)
Bahamas
3/2002
367
109
Capable
DP
5; 4.3; 92/43; 20.4 A-Frame
DP DSV Kestrel (11)
Vanuatu
9/2006
323
80
Capable
DP
40; 15; 10; Hydralift HLR 308
DP DSV Mystic Viking (11)
Bahamas
6/2001
253
60
Capable
DP
50
DP MSV Texas Horizon (11)
Vanuatu
12/2007
341
96
Capable
DP
113
DP MSV Uncle John (11)
Bahamas
11/1996
254
102
Capable
DP
2×100
DSV American Constitution (11)
Panama
11/2005
200
46
Capable
4 point
20.41
DSV Cal Diver I (11)
U.S.
7/1984
196
40
Capable
4 point
20
DSV Cal Diver II (11)
U.S.
6/1985
166
32
Capable
4 point
40 A-Frame
Surface Diving —
             
Cal Diver IV (11)
U.S.
3/2001
120
24
DSV American Star (11)
U.S
11/2005
165
30
4 point
9.072
DSV American Triumph (11)
U.S.
11/2005
164
32
4 point
13.61
DSV American Victory (11)
U.S.
11/2005
165
34
4 point
9.072
DSV Dancer (11)
U.S.
3/2006
173
34
4 point
30
DSV Mr. Fred (11)
U.S.
3/2000
166
36
4 point
25
DSV Midnight Star (11)
Vanuatu
6/2006
197
42
4 point
20 and 40
Fox (11)
U.S.
10/2005
130
42
Mr. Jack (11)
U.S.
1/1998
120
22
10
Mr. Jim (11)
U.S.
2/1998
110
19
Polo Pony (11)
U.S.
3/2001
110
25
Sterling Pony (11)
U.S.
3/2001
110
25
White Pony (11)
U.S.
3/2001
116
25
__________

(1)
Under government regulations and our insurance policies, we are required to maintain our vessels in accordance with standards of seaworthiness and safety set by government regulations and classification organizations. We maintain our fleet to the standards for seaworthiness, safety and health set by the ABS, Bureau Veritas (“BV”), Det Norske Veritas (“DNV”), Lloyds Register of Shipping (“Lloyds”), and the USCG. The ABS, BV, DNV and Lloyds are classification societies used by ship owners to certify that their vessels meet certain structural, mechanical and safety equipment standards.
   
(2)
Represents the date we placed the vessel in service and not the date of commissioning.
   
(3)
Currently under conversion into a deepwater pipelay asset with completion expected in the second half of  2009.
   
(4)
Subject to vessel mortgages securing our Senior Credit Facilities described in Item 8. Financial Statements and Supplementary Data “— Note 11 — Long-term Debt.”
   
(5)
Former ferry vessel undergoing conversion into DP floating production unit for initial use on our Phoenix field. See Production Facilities on page 31.


 
29

 


   
   
(6)
Subject to vessel mortgage securing our MARAD debt described in Item 8. Financial Statements and Supplementary Data “— Note 11 — Long-term Debt.”
   
(7)
Currently under construction and expected to be placed into service in second quarter 2009.
   
(8)
Owned and operated by our domestic subsidiary under a secured lien, except for one ROV and one Trencher which are leased.
   
(9)
Average age of our fleet of ROVs, trenchers and ROV Drills is approximately 4.5 years.
   
(10)
Leased.
   
(11)
Subject to vessel mortgages securing CDI’s $675 million credit facility described in Item 8. Financial Statements and Supplementary Data “— Note 11 — Long-term Debt.”
   
In addition to CDI’s saturation diving vessels, CDI currently owns ten portable saturation diving systems, including six acquired from Fraser.

The following table details the average utilization rate for our vessels by category (calculated by dividing the total number of days the vessels in this category generated revenues by the total number of calendar days in the applicable period) for the years ended December 31, 2008, 2007 and 2006:

     
Year Ended December 31,
 
     
2008
     
2007
     
2006
 
Contracting Services:
                       
  Pipelay
   
92
%
   
79
%
   
87
%
  Well operations
   
70
%
   
71
%
   
81
%
  ROVs
   
73
%
   
78
%
   
76
%
Shelf Contracting
   
60
%
   
65
%
   
84
%

We incur routine drydock, inspection, maintenance and repair costs pursuant to Coast Guard regulations and in order to maintain our vessels in class under the rules of the applicable class society. In addition to complying with these requirements, we have our own vessel maintenance program that we believe permits us to continue to provide our customers with well maintained, reliable vessels. In the normal course of business, we charter in other vessels on a short-term basis, such as tugboats, cargo barges, utility boats and dive support vessels.

PRODUCTION FACILITIES

Through our interest in Deepwater Gateway, a limited liability company in which Enterprise Products Partners L.P. is the other member, we own a 50% interest in the Marco Polo TLP, which was installed on Green Canyon Block 608 in 4,300 feet of water. Deepwater Gateway was formed to construct, install and own the Marco Polo TLP in order to process production from Anadarko Petroleum Corporation’s Marco Polo field discovery at Green Canyon Block 608. Anadarko required 50,000 barrels of oil per day and 150 million feet per day of processing capacity for Marco Polo. The Marco Polo TLP was designed to process 120,000 barrels of oil per day and 300 million cubic feet of gas per day and payload with space for up to six subsea tie backs.

We also own a 20% interest in Independence Hub, an affiliate of Enterprise Products Partners L.P., that owns the Independence Hub platform, a 105 foot deep draft, semi-submersible platform located in Mississippi Canyon block 920 in a water depth of 8,000 feet that serves as a regional hub for natural gas production from multiple ultra-Deepwater fields in the previously untapped eastern Gulf of Mexico. First production began in July 2007. The Independence Hub facility is capable of processing up to 1 billion cubic feet (Bcf) per day of gas.

We own a 20% interest in the Gunnison truss spar facility, together with the operator Kerr-McGee Oil & Gas Corporation (“Kerr-McGee”), which owns a 50% interest, and Nexen, Inc., which owns the remaining 30% interest. The Gunnison spar, which is moored

 
30

 

in 3,150 feet of water and located on Garden Banks Block 668, has daily production capacity of 40,000 barrels of oil and 200 million cubic feet of gas. This facility is designed with excess capacity to accommodate production from satellite prospects in the area.

Further, we, along with Kommandor Rømø, a Danish corporation, formed a joint venture company called Kommandor LLC to convert a ferry vessel into a floating production unit to be named the Helix Producer I. The total cost of the ferry and its initial conversion is estimated to range between $150 million and $160 million,   We have provided $84.7 million in interim construction financing through December 31, 2008 to the joint venture on terms that would equal an arms length financing transaction, and Kommandor Rømø has provided $5 million on the same terms.

Total equity contributions and indebtedness guarantees provided by Kommandor Rømø are expected to total $42.5 million.  The remaining costs to complete the project will be provided by us through equity contributions.  Under the terms of the operating agreement for the joint venture, if Kommandor Rømø elects not to make further contributions to the joint venture, the ownership interests in the joint venture will be adjusted based on the relative contributions of each partner to the total of all contributions and project financing guarantees.

Upon completion of the initial conversion, scheduled for second quarter 2009, we will charter the Helix Producer I from Kommandor LLC, and plan to install, at 100% our cost, processing facilities and a disconnectable fluid transfer system on the Helix Producer I for initial use on our Phoenix field. The cost of these additional facilities is estimated to approximate $200 million when the work is expected to be completed in early 2010.  As of December 31, 2008, approximately $210.1 million of costs related to the purchase of the Helix Producer I ($20 million), conversion of the Helix Producer I and construction of the additional facilities had been incurred, with an additional $4.9 million committed.  Kommandor LLC qualified as a variable interest entity under FIN 46(R).  We determined that we were the primary beneficiary of Kommandor LLC and thus have consolidated the financial results of Kommandor LLC as of December 31, 2008 in our Production Facilities segment.  Kommandor LLC has been a development stage enterprise since its formation in October 2006.

 
31

 

SUMMARY OF NATURAL GAS AND OIL RESERVE DATA

We employ full-time experienced reserve engineers and geologists who are responsible for determining proved reserves in conformance with SEC guidelines. Engineering reserve estimates were prepared by us based upon our interpretation of production performance data and sub-surface information derived from the drilling of existing wells. Our internal reservoir engineers and independent petroleum engineers analyzed 100% of our United States oil and gas fields on an annual basis (107 fields as of December 31, 2008). We consider any field with discounted future net revenues of 1% or greater of the total discounted future net revenues of all our fields to be significant. An “engineering audit,” as we use the term, is a process involving an independent petroleum engineering firm’s (Huddleston & Co., Inc. (“Huddleston”)) extensive visits, collection and examination of all geologic, geophysical, engineering and economic data requested by the independent petroleum engineering firm. Our use of the term “engineering audit” is intended only to refer to the collective application of the procedures which Huddleston was engaged to perform and may be defined and used differently by other companies.

The engineering audit of our reserves by the independent petroleum engineers involves their rigorous examination of our technical evaluation, interpretation and extrapolations of well information such as flow rates and reservoir pressure declines as well as other technical information and measurements. Our internal reservoir engineers interpret this data to determine the nature of the reservoir and ultimately the quantity of proved oil and gas reserves attributable to a specific property. Our proved reserves in this Annual Report include only quantities that we expect to recover commercially using current prices, costs, existing regulatory practices and technology. While we are reasonably certain that the proved reserves will be produced, the timing and ultimate recovery can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and changes in projections of long-term oil and gas prices. Revisions can include upward or downward changes in the previously estimated volumes of proved reserves for existing fields due to evaluation of (1) already available geologic, reservoir or production data or (2) new geologic or reservoir data obtained from wells. Revisions can also include changes associated with significant changes in development strategy, oil and gas prices, or the related production equipment/facility capacity. Huddleston also examined our estimates with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance.

In the conduct of the engineering audit, Huddleston did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties or sales of production. However, if in the course of the examination something came to the attention of Huddleston which brought into question the validity or sufficiency of any such information or data, Huddleston did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data. Furthermore, in instances where decline curve analysis was not adequate in determining proved producing reserves, Huddleston evaluated our volumetric analysis, which included the analysis of production and pressure data. Each of the PUDs analyzed by Huddleston included volumetric analysis, which took into consideration recovery factors relative to the geology of the location and similar reservoirs. Where applicable, Huddleston examined data related to well spacing, including potential drainage from offsetting producing wells in evaluating proved reserves for un-drilled well locations.

The engineering audit by Huddleston included 100% of our producing properties together with essentially all  of our non-producing and undeveloped properties. Properties for analysis were selected by us and Huddleston based on discounted future net revenues. All of our significant properties were included in the engineering audit and such audited properties constituted approximately 97% of the total discounted future net revenues. Huddleston also analyzed the methods utilized by us in the preparation of all of the estimated reserves and revenues. Huddleston represents in its audit report that it believes our methodologies are consistent with the methodologies required by the SEC, Society of Petroleum Engineers (“SPE”) and FASB. There were no limitations imposed, nor limitations encountered by us or Huddleston.

The table below sets forth information, as of December 31, 2008, with respect to estimates of net proved reserves. Proved reserves cannot be measured exactly because the estimation of reserves involves numerous judgmental determinations. Accordingly, reserve estimates must be continually revised as a result of new information obtained from drilling and production history, new geological and geophysical data and changes in economic conditions.

 
32

 


     
As of December 31, 2008
 
     
Proved Developed Reserves
     
Proved Undeveloped Reserves
     
Total Proved Reserves
 
United States:
                       
   Gas (Bcf)
   
257
     
203
     
460
 
   Oil (MMBbls)
   
13
     
19
     
32
 
     Total (Bcfe)
   
333
     
319
     
652
 
                         
United Kingdom:
                       
   Gas (Bcf)
   
1
     
12
     
13
 
   Oil (MMBbls)
   
     
     
 
     Total (Bcfe)
   
1
     
12
     
13
 
                         
Total:
                       
   Gas (Bcf)
   
258
     
215
     
473
 
   Oil (MMBbls)
   
13
     
19
     
32
 
     Total (Bcfe)
   
334
     
331
     
665
 

For additional information regarding estimates of oil and gas reserves, including estimates of proved and proved developed reserves, the standardized measure of discounted future net cash flows, and the changes in discounted future net cash flows, see Item 8. Financial Statements and Supplementary Data “— Note 21— Supplemental Oil and Gas Disclosures.”

Significant Oil and Gas Properties

Our oil and gas properties consist primarily of interests in developed and undeveloped oil and gas leases. As of December 31, 2008, we had exploration, development and production operations in the United States, primarily in the Gulf of Mexico. In December 2006, we acquired the Camelot field, located in the North Sea, in which we subsequently sold a 50% interest in June 2007. This is our only developed oil and gas property in the United Kingdom.

Our U.S. operations accounted for approximately 99% of our 2008 production and approximately 98% of total proved reserves at December 31, 2008 (87% of such total reserves are PUDs, PDSI and PDNP). Further, our proved producing reserves at December 31, 2008 are expected to experience annual decline rates ranging from 30% to 40% over the next ten years. The following table provides a brief description of our domestic and international oil and gas properties we consider most significant to us at December 31, 2008:
 
     
 
 
 
Development Location
     
 
Net Total Proved Reserves (Bcfe)
   
 
Net Proved Reserves Mix
 
2008 Net Production (Bcfe)
   
Average WI%
   
Expected First Production
 
 
Oil
 %
 
 
Gas
 %
United States  Offshore:
                                         
  Deepwater
                                         
    Bushwood(1)
   
 
U.S. GOM
     
 
314
   
 
10
 
 
90
 
-
   
51
   
Jan 2009
 
    Phoenix(2)
   
U.S. GOM
     
42
   
79
 
21
 
-
   
70
   
2010
 
    Gunnison(3)
   
U.S. GOM
     
23
   
51
 
49
 
4
   
19
   
Producing
 

 
   
 
 
 
Development Location
 
 
Net Total Proved Reserves (Bcfe)
 
 
Net Proved Reserves Mix
   
2008 Net Production (Bcfe)
   
Average WI%
   
Expected First Production
 
Oil
%
 
Gas %
  Outer Continental Shelf
 
U.S. GOM
                               
    East Cameron 346
 
U.S. GOM
 
36
 
80
 
20
   
1
   
75
   
Producing
 
    High Island A557
 
U.S. GOM
 
22
 
74
 
26
   
2
   
100
   
Producing
 
    South Timbalier 86/63
 
U.S. GOM
 
32
 
39
 
61
   
4
   
91
   
Producing
 
    South Pass 89
 
U.S. GOM
 
22
 
73
 
17
   
1
   
27
   
Producing
 
    Mobile 863
 
U.S. GOM
 
20
 
-
 
100
   
-
   
83
   
2010
 
    West Cameron 170
 
U.S. GOM
 
16
 
30
 
70
   
1
   
55
   
Producing
 
    East Cameron 339
 
U.S. GOM
 
10
 
69
 
31
   
4
   
100
   
Producing
 
    Eugene Island 302
 
U.S. GOM
 
10
 
63
 
37
   
1
   
58
   
PDSI 2010
 
    South Marsh Island 130
 
U.S. GOM
 
13
 
73
 
27
   
2
   
100
   
Producing
 
United Kingdom Offshore(4)
 
UK Offshore
 
13
 
-
 
100
   
1
   
50
   
PDSI 2009
 

(1)
Garden Banks Blocks  462, 463, 506 and 507  (formerly Noonan/Danny).
   
(2)
Green Canyon Blocks 236, 237, 238 and 282.
   
(3)
An outside operated property comprised of Garden Banks Blocks 625, 667, 668 and 669.
   
(4)
Consists of our only developed property in the United Kingdom, Camelot.

United States Offshore

Deepwater

The estimated proved reserves associated with our three fields in the Deepwater of the Gulf of Mexico totaled 379 Bcfe or approximately 57 % of our total estimated proved reserves at December 31, 2008. We are the operator of two of the three fields, which comprised approximately 94% of our Deepwater proved reserves (approximately 53% of total proved reserves). Gunnison, a non-operated field, has been producing since December 2003. Our net production in Deepwater totaled approximately 8 Bcfe in 2008. As long as we continue to have interest in properties in Deepwater, we will continue to advance our  Deepwater development activities and may pursue additional future exploration opportunities.

Outer Continental Shelf

Our estimated proved reserves for our 102 fields in the Gulf of Mexico on the OCS totaled  approximately 273 Bcfe or 41% of our total estimated proved reserves as of December 31, 2008. Our net production from the OCS properties totaled approximately 39 Bcfe in 2008. Our largest field on the OCS is East Cameron Block 346, whose total estimated proved reserve represents approximately 13% of our aggregated OCS estimated proved reserves (or approximately 5% of total estimated proved reserves). No other individual OCS field comprised over 5% of total estimated proved reserves. We are the operator of 77% of our OCS properties whose composite estimated proved reserves totals 210 Bcfe.

United Kingdom Offshore

In December 2006, we acquired the Camelot field, located in the North Sea, in which we subsequently sold a 50% interest in June 2007. This is our only developed oil and gas property in the United Kingdom.   The results of our UK operations were immaterial for each of the three years ended  December 31, 2008,  2007 and 2006, respectively.

 
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Production, Price and Cost Data

Production, price and cost data for our oil and gas operations in the United States are as follows:
     
Year Ended December 31,
 
     
2008
     
2007
     
2006
 
Production:
                       
   Gas (Bcf)
   
31
     
42
     
28
 
   Oil (MMBbls)
   
3
     
4
     
3
 
     Total (Bcfe)
   
47
     
65
     
48
 
                         
Average sales prices realized (including hedges):
                       
   Gas (per Mcf)
 
$
9.29
   
$
7.69
   
$
7.86
 
   Oil (per Bbl)
 
$
92.22
   
$
67.68
   
$
60.41
 
   Total (per Mcfe)
 
$
11.43
   
$
8.93
   
$
8.79
 
                         
Average production cost per Mcfe
 
$
2.99
   
$
1.83
   
$
1.85
 
Average depletion and amortization per Mcfe
 
$
4.21
   
$
3.54
   
$
2.79
 

Productive Wells

The number of productive oil and gas wells in which we held interest as of December 31, 2008 is as follows:

     
Oil Wells
     
Gas Wells
     
Total Wells
 
     
Gross
     
Net
     
Gross
     
Net
     
Gross
     
Net
 
United States – Offshore
   
305
     
231
     
375
     
200
     
680
     
431
 

Productive wells are producing wells and wells capable of production. A gross well is a well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned. A net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof. One or more completions in the same borehole are counted as one well in this table.

The following table summarizes multiple completions and non-producing wells as of December 31, 2008:

     
Oil Wells
     
Gas Wells
     
Total Wells
 
     
Gross
     
Net
     
Gross
     
Net
     
Gross
     
Net
 
Not producing  (shut-in)
   
44
     
32
     
105
     
62
     
149
     
94
 
Multiple completions
   
221
     
169
     
281
     
155
     
502
     
324
 

Developed and Undeveloped Acreage

The developed and undeveloped acreage (including both leases and concessions) that we held at December 31, 2008 is as follows:

     
Undeveloped
     
Developed
 
     
Gross
     
Net
     
Gross
     
Net
 
United States – Offshore
   
348,528
     
280,831
     
568,253
     
307,880
 
United Kingdom – Offshore
   
25,406
     
12,703
     
9,778
     
4,889
 
        Total
   
373,934
     
293,534
     
578,031
     
312,769
 

Developed acreage is acreage spaced or assignable to productive wells. A gross acre is an acre in which a working interest is owned. A net acre is deemed to exist when the sum of fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

 
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Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas regardless of whether or not such acreage contains proved reserves. Included within undeveloped acreage are those leased acres (held by production under the terms of a lease) that are not within the spacing unit containing, or acreage assigned to, the productive well so holding such lease. The current terms of our leases on undeveloped acreage are scheduled to expire as shown in the table below (the terms of a lease may be extended by drilling and production operations):

     
Offshore
 
     
Gross